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Home My WebLink AboutAdditions to existing hydro analysisAlaska Energy Data Gateway https://akenergygateway.alaska.edu/ Generated on Dataset Name: Dataset Description: Variables Table REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project monthly data REF project REF project REF project REF project REF project REF project REF project REF project REF project REF project REF project REF project REF project REF project REF project REF project fuel type fuel type fuel type fuel type fuel type fuel type fuel type fuel type fuel type fuel type fuel type fuel type utility utility utility utility utility utility regulatory status utility regulatory status utility type utility type REF technology type REF technology type Tables Name REF project REF project monthly data REF technology type fuel type utility utility regulatory status utility type Unique Identifiers The following individual variables uniquely identify rows: The following variable combinations uniquely identify rows: We ask that you include the following citation in publications that make use of this data: Alaska Energy Data Gateway, developed by the Institute of Social and Economic Research, University of Alaska Anchorage, is supported by the U.S. Department of Energy (DOE), Office of Science, Basic Energy Sciences (BES), under EPSCoR Award # DE-SC0004903 (database and web application development), and by Alaska Energy Authority (Renewable Energy Fund data management and reporting). Database and web hosting is provided by the Institute of Social and Economic Research, University of Alaska Anchorage. 10/11/2019 11:31:52 AM REF project monthly data Monthly data reported to the Alaska Energy Authority for a particular renewable energy project by a grantee of that project Name id actual_ff_om_hours actual_ff_om_price actual_ff_price actual_ff_quantity actual_gross_re_electric_generation actual_net_electricity_to_secondary_loads actual_net_heat_output actual_net_heat_to_secondary_loads actual_net_re_electric_generation actual_re_fuel_price_chips actual_re_fuel_price_cords actual_re_fuel_price_electricity actual_re_fuel_price_pellets actual_re_fuel_quantity_chips actual_re_fuel_quantity_cords actual_re_fuel_quantity_electricity actual_re_fuel_quantity_pellets actual_re_om_hours actual_re_om_price actual_total_other_ff_om_costs actual_total_other_re_om_costs alternate_total_actual_ff_om alternate_total_actual_re_om alternate_total_cost_of_re_fuel biomass_moisture_content comments electric_efficiency_after_re_integration month nonscheduled_maintenance_hours notes parasitic_load scheduled_maintenance_hours year project__id project__electric_efficiency_prior_to_re_integration project__electric_generation_fuel_displaced project__goal_net_heat_delivered project__goal_net_re_electric_generation project__heat_efficiency_after_re_integration project__heat_efficiency_prior_to_re_integration project__heat_fuel_displaced project__latitude project__longitude project__master_project_code project__name project__project_expected_completion_date project__project_full_commission_date project__project_notes project__project_operation_start_date project__electric_generation_fuel_displaced_type__id project__electric_generation_fuel_displaced_type__abbreviation project__electric_generation_fuel_displaced_type__conversion_factor_mmbtu project__electric_generation_fuel_displaced_type__emission_factor project__electric_generation_fuel_displaced_type__name project__electric_generation_fuel_displaced_type__physical_units project__heat_fuel_displaced_type__id project__heat_fuel_displaced_type__abbreviation project__heat_fuel_displaced_type__conversion_factor_mmbtu project__heat_fuel_displaced_type__emission_factor project__heat_fuel_displaced_type__name project__heat_fuel_displaced_type__physical_units project__re_utility__id project__re_utility__certificate project__re_utility__eia_operator_id project__re_utility__name project__re_utility__pce_id project__re_utility__regulatory_status__id project__re_utility__regulatory_status__name project__re_utility__utility_type__id project__re_utility__utility_type__name project__technology_type__id project__technology_type__name Description A renewable energy project in the Renewable Energy Fund program. The project may or may not have reached any given stage of development, may or may not have received funding, and may be associated with one or more applications and one or more grants. Monthly data reported to the Alaska Energy Authority for a particular renewable energy project by a grantee of that project An energy source or type of technology that describes a renewable energy project Types of fuel used to generate electricity or heat, physical units in used to measure the fuel and energy content (MMBtu) per physical unit of fuel. EIA typically publishes data in Barrels for liquids. All liquids presented in gallons using a conversion factor of 1 Barrel = 42 gallons. MMBtu adjusted accordingly. EIA does not track HAGO separately. HAGO information from Golden Valley Electric Association, which uses the fuel for electric generation. A utility or independent power producer (IPP) Regulatory status of a Utility Ownership type of a Utility id project, year, month Label ID Actual FF (fossil fuel) O&M hours Actual FF O&M price Actual fossil fuel price Actual fossil fuel quantity Actual Gross RE Electric Generation Actual Net Electricity to Secondary Loads Actual Net Heat Output Actual Net Heat to Secondary Loads Actual Net RE Electric Generation Actual RE fuel price-chips Actual RE fuel price-cords Actual RE fuel price-electricity Actual RE fuel price-pellets Actual RE fuel quantity-chips Actual RE fuel quantity-cords Actual RE fuel quantity-electricity Actual RE fuel quantity-pellets Actual RE O&M hours Actual RE O&M price Actual total other FF O&M costs Actual total other RE O&M costs Alternate Total Actual FF O&M Alternate Total Actual RE O&M Alternate total cost of RE fuel Biomass Moisture Content Comments Electric generation efficiency after RE integration month Nonscheduled Maintenance Hours Notes Parasitic Load Scheduled Maintenance Hours year ID Electric generation efficiency prior to RE integration Electric Generation Fuel Displaced Goal Net Heat Delivered Goal Net RE Electric Generation Heating system efficiency after RE integration Heating system efficiency prior to RE integration Heat Fuel Displaced latitude longitude master project code name Project expected completion date Project full commission date Project notes Project operation start date ID abbreviation conversion factor mmbtu emission factor name physical units ID abbreviation conversion factor mmbtu emission factor name physical units ID certificate EIA Operator ID name PCE ID ID name ID name ID name Source Alaska Energy Authority. Data import from AEA's REval data set. Alaska Energy Authority. Data imported from Grantee's REF Performance Reporting Forms for wind projects; manual data entry by AEA's Program Managers for all other technologies. Alaska Energy Authority. REval data file U.S. Department of Energy, Energy Information Administration. Energy Information Administration (EIA); Alaska Energy Authority (AEA); Regulatory Commission of Alaska (RCA); Institute of Social and Economic Research (ISER) Type Integer Integer Decimal number Decimal number Integer Integer Integer Decimal number Integer Integer Decimal number Decimal number Decimal number Decimal number Integer Integer Integer Decimal number Integer Decimal number Decimal number Decimal number Decimal number Decimal number Decimal number Integer Text Decimal number Integer Integer Text Integer Integer Integer Integer Decimal number Boolean (Either True, False or None) Integer Integer Integer Integer Boolean (Either True, False or None) Decimal number Decimal number Integer String (up to 200) Date (without time) Date (without time) Text Date (without time) Integer String (up to 10) Floating point number Decimal number String (up to 100) String (up to 100) Integer String (up to 10) Floating point number Decimal number String (up to 100) String (up to 100) Integer Boolean (Either True, False or None) Integer String (up to 50) Integer Integer String (up to 50) Integer String (up to 50) Integer String (up to 100) Units hours $/hour dollars per physical unit units depend on displaced fuel type kWh kWh MMBtu MMBtu kWh $/green ton $/cord $/kWh $/ton green tons cords kWh pellet tons hours $/hour $ $ $ $ $ percent kWh/gal for diesel, kWh/MCF for natural gas hours kWh hours kWh per physical unit % % Decimal Degrees Decimal Degrees kg CO2/MMBtu kg CO2/MMBtu Description Number of work hours spent specifically for the operation and maintenance of the FF system Average hourly wage for the operation and maintenance of the FF system during the reporting period Average price of fuel delivered to the project. Physical units are MCF for natural gas, short tons for coal, and gallons for all other fuel types, including propane. Number of diesel gallons or mcf used in production of electricity or heat (not fuel displaced) by current system Total amount of electricity produced by the RE system including parasitic load Total amount of electricity going to a secondary load from RE, may include nonrenewable sources Total amount of thermal energy produced for heating by REF funded renewable energy system Total amount of heat going to a secondary load from RE, may include nonrenewable sources Total monthly amount of electricity produced by the RE system delivered to the bus bar. Includes any secondary load kWh. It equals gross production minus parasitic load. Weighted annual average price of wood chips used by RE system in community served Weighted annual average price of cordwood fuel used by RE system in the community served Dollars per kWh of electricity used for generation by the RE system (not parasitic load) Weighted annual average price wood pellets used by RE system in community served Total amount of green tons of wood chips used by REF biomass system used for heat or electricity generation Amount of RE fuel used for generation Amount of electricity used for generation by the RE system (not parasitic load) Total amount of wood pellet tons used by REF biomass system used for heat or electricity generation Number of work hours spent in the operation and maintenance of the RE system Average wage per hour paid to personnel performing the operation and maintenance of the RE system Additional O&M costs such as travel, shipping, tech support, equipment rental Additional O&M costs such as travel, shipping, tech support, equipment rental Total dollars spent on O&M as estimated by system manager or project manager; used when detailed data not available Total dollars spent on O&M as estimated by system manager or project manager; used when detailed data not available Total dollars spent on fuel used for renewable energy generation, if quantity or price per unit is unknown Moisture content level in wood chips used for fuel by REF biomass system in heat or electricity generation Comments regarding O&M or electricity or heat generation of the RE system Electric generation average efficiency of fossil fuel system after the integration of RE Month of reported data Number of hours the RE did not operate due to need for repair or unscheduled maintenance Energy consumed for operation of the RE system that is upstream of the busbar or other point of connection to the power system. Number of hours the RE system did not operate due to scheduled maintenance Calendar year of reported data Fossil fuel system electric generation average efficiency prior to the integration of the renewable energy system. Physical units are MCF for natural gas, short tons for coal, and gallons for all other fuel types, including propane. Identifies whether the project displaces fuel used for electric generation. Fossil fuel heating system average efficiency after the integration of RE Fossil fuel heating system average efficiency prior to the integration of RE Identifies whether the project displaces fuel used for heating The angular distance of the primary community served by the project north of the earth's equator. The is a geographic coordinate that specifies the east-west position of the primary community served by the project. The Master Project Code (MPC) of the project defines a unique renewable energy project awarded funds through the Renewable Energy Fund program. A MPC may have one or more REF Applications, one or more REF Award Codes and may be funded through one or more REF rounds. Name of renewable energy project that was awarded funds through the Renewable Energy Fund program. Date on which the project is expected to start producing energy, regardless of project phase. Leave blank if unknown. Date on which the project became fully commissioned Notes on O&M contract or other general project information Date on which the project began to produce electricity or heat Abbreviation code for type of fuel used to generate electricity or heat as defined by the U.S. Department of Energy, Energy Information Administration Number of million British Thermal units of energy per physical unit for a fuel type. Number of kilograms of carbon dioxide per one million British Thermal Units. Name of the type of fuel used to generate electricity or heat as defined by the U.S. Department of Energy, Energy Information Administration. Physical units for the fuel type. Abbreviation code for type of fuel used to generate electricity or heat as defined by the U.S. Department of Energy, Energy Information Administration Number of million British Thermal units of energy per physical unit for a fuel type. Number of kilograms of carbon dioxide per one million British Thermal Units. Name of the type of fuel used to generate electricity or heat as defined by the U.S. Department of Energy, Energy Information Administration. Physical units for the fuel type. Indicates whether this utility has an active certificate to operate from the RCA Operator ID assigned by the Energy Information Administration Name of the certified utility or independent power producer generating electricity and/or servicing a particular community or communities. Utility regulatory status Utility or independent power producer ownership type A category of energy source or type of technology, assigned by the Alaska Energy Authority to a renewable energy project under the Renewable Energy Fund program. Plant Name Blue Lake Cooper Lake Terror Lake Whitman YEAR 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2014 2015 2016 2017 2018 Plant Name Source EIA EIA EIA EIA EIA EIA EIA REF EIA REF EIA REF EIA REF EIA EIA EIA EIA EIA EIA EIA EIA EIA REF EIA REF EIA REF EIA EIA EIA EIA EIA EIA EIA EIA REF EIA REF EIA REF EIA REF EIA REF EIA REF EIA REF EIA REF EIA Net Generation (Megawatthours) 55760 58422 58422 56154 55672 52463 40707 8755 59501 60072 69018 69759 59004 60210 56170 6663 33262 45390 28759 77589 35928 32050 16425 2993.688 86666 6020 25713 26327 59832 120879 98551 123964 114186 131121 119142 134031 36454.9 128893 119627.7 124484 125411 137014 137996 121969 2531.038 8712 8828.431 7649 7717.713 9373 9465.287 6998 8755000 60072000 69759000 60210000 2993688 6020000 36454900 119627700 125411000 137996000 2531038 8828431 7717713 9465287 Months of data 3 12 12 12 12 12 11 11 12 12 12 4 12 12 12 Notes Partial year (3 months) Stetson Creek Stetson Creek Stetson Creek Stetson Creek Unit 3 Unit 3 Unit 3 Unit 3 Blue Lake add 9.6 MW to generation capacity and raise the spill level by 83 ft The analysis is based on 9.4 MW, this may be a typo. The proposed modifications will increase hydro capacity by 32 GWH, Original Expansion Total Percent of total Terror Lake Increase generation capacity from 20MW to 30 MW Did not increase storage capacity (no more kWh available) Not really increase kWh produced but reduce kWh produced by diesel--Improve integration with wind This should be measured in diesel not consumed, not in kWh produced Not sure how this will go into a database…(that we no longer have) Track the diesel by KEA over those same years…. Is there some way to come up with a way to not double-count with the wind? Master Project Code 10099 10118 10017 kW 8910 9600 18567 0.517046372596542 Technology Type Wind Hydro Hydro MWh 62500 32000 92500 0.345945945945946 Fuel Displaced Type Diesel Diesel Distillate Fuel Oil Grantee Kodiak Electric Association, Inc. Kodiak Electric Association, Inc. City and Borough of Sitka Project Name Pillar Mountain Wind Project Terror Lake Unit 3 Hydroelectric Project Blue Lake Hydroelectric Expansion Project Operation Start Date 2010 Sep 2014 Jan 2014 Nov Average Fossil Fuel Price ($) 2.64 4.06 2009 Energy Production Electrical (MWh) 6164 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 434.1 Value ($ x 1000) 1406.5 2010 Energy Production Electrical (MWh) 12288 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 865.4 Value ($ x 1000) 2972.7 2011 Energy Production Electrical (MWh) 12448 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 870.7 Value ($ x 1000) 2873.3 2012 Energy Production Electrical (MWh) 16200.5 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 1140.9 Value ($ x 1000) 4211.8 2013 Energy Production Electrical (MWh) 25437.9 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 1791.4 Value ($ x 1000) 6134 2014 Energy Production Electrical (MWh) 23038.5 9304.6 8755 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 1622.4 620.3 673.5 Value ($ x 1000) 5066.4 2760.4 2155.1 2015 Energy Production Electrical (MWh) 29107.3 118044.4 59272 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 2049.8 8431.7 4559.4 Value ($ x 1000) 5416.6 34232.9 14593.8 2016 Energy Production Electrical (MWh) 29314.4 124484.1 69041 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 2064.4 8891.7 5310.8 Value ($ x 1000) 3728.3 25430.3 12852.2 2017 Energy Production Electrical (MWh) 16849 106079.4 60209.2 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 1186.54929577465 7577.1 4631.5 Value ($ x 1000) 2610.40845070423 22579.8 11856.6 Cumulative Total (2009-2017) Energy Production Electrical (MWh) 170817 357912.5 197277.2 Thermal (MMBtu) Fuel Displaced Diesel (Gal x 1000) 12025.6 25520.9 15175.2 Value ($ x 1000) 34420 85003.4 41457.7 Row Labels Blue Lake Hydroelectric Expansion Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Terror Lake Unit 3 Hydroelectric Project Whitman Lake Hydro Grand Total year 2014 2015 2016 2017 2015 2016 2017 2014 2015 2016 2017 2014 2015 2016 2017 Sum of actual_gross_re_electric_generation 8755000 60072000 69759000 60210000 2993688 6020000 26327 36454900 119627700 125411000 137996000 2531038 8828431 7717713 9465287 655868084 Count of actual_gross_re_electric_generation 3 12 12 12 12 12 11 11 12 12 12 4 12 12 12 161 YEAR 2017 2017 2017 2017 2016 2016 2016 2016 2015 2015 2015 2015 2014 2014 2014 Plant Id 2018 2018 2018 2018 Plant Id 71 93 6291 58977 71 93 6291 58977 71 93 6291 58977 71 93 6291 Combined Heat And Power Plant 71 93 6291 58977 Combined Heat & Power Plant N N N N N N N N N N N N N N N Nuclear Unit Id N N N N Plant Name Terror Lake Microgrid Blue Lake Hydro Cooper Lake Whitman Terror Lake Blue Lake Hydro Cooper Lake Whitman Terror Lake Blue Lake Hydro Cooper Lake Whitman Terror Lake Blue Lake Hydro Cooper Lake Plant Name . . . . Operator Name Kodiak Electric Assn Inc City & Borough of Sitka - (AK) Chugach Electric Assn Inc Ketchikan Public Utilities Kodiak Electric Assn Inc City & Borough of Sitka - (AK) Chugach Electric Assn Inc Ketchikan Public Utilities Kodiak Electric Assn Inc City & Borough of Sitka - (AK) Chugach Electric Assn Inc Ketchikan Public Utilities Kodiak Electric Assn Inc City & Borough of Sitka - (AK) Chugach Electric Assn Inc Operator Name Terror Lake Microgrid Blue Lake Hydro Cooper Lake Whitman Operator Id 10433 17271 3522 10210 10433 17271 3522 10210 10433 17271 3522 10210 10433 17271 3522 Operator Id Kodiak Electric Assn Inc City & Borough of Sitka - (AK) Chugach Electric Assn Inc Ketchikan Public Utilities Reported Prime Mover HY HY HY HY HY HY HY HY HY HY HY HY HY HY HY Plant State 10433 17271 3522 10210 Reported Fuel Type Code WAT WAT WAT WAT WAT WAT WAT WAT WAT WAT WAT WAT WAT WAT WAT Census Region AK AK AK AK Physical Unit Label NERC Region PACN PACN PACN PACN Elec_Quantity_Jan 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reserved ASCC ASCC ASCC Elec_Quantity_Feb 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 NAICS Code Elec_Quantity_Mar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 EIA Sector Number 22 22 22 22 Elec_Quantity_Apr 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Sector Name 1 1 1 1 Elec_Quantity_May 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reported Prime Mover Electric Utility Electric Utility Electric Utility Electric Utility Elec_Quantity_Jun 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reported Fuel Type Code HY HY HY HY Elec_Quantity_Jul 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 AER Fuel Type Code WAT WAT WAT WAT Elec_Quantity_Aug 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reserved HYC HYC HYC HYC Elec_Quantity_Sep 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reserved Elec_Quantity_Oct 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Physical Unit Label Elec_Quantity_Nov 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Quantity January Elec_Quantity_Dec 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Quantity February 0 0 0 0 Elec_MMBtuJan 154702 66621 29033 10583 109009 60438 75892 6698 116329 53701 14824 7863 117112 35568 28004 Quantity March 0 0 0 0 Elec_MMBtuFeb 70981 30567 13321 4856 89918 49853 62601 5525 97805 45150 12463 6611 105696 32101 25274 Quantity April 0 0 0 0 Elec_MMBtuMar 63385 27296 11895 4336 114849 63676 79958 7057 80849 37322 10303 5465 95610 29038 22863 Quantity May 0 0 0 0 Elec_MMBtuApr 107126 46133 20104 7328 72134 39994 50220 4432 97910 45198 12477 6618 102482 31125 24506 Quantity June 0 0 0 0 Elec_MMBtuMay 115959 49937 21762 7933 47828 26518 33298 2939 95049 43878 12112 6424 89607 27215 21427 Quantity July 0 0 0 0 Elec_MMBtuJun 68506 29502 12856 4686 55395 30713 38566 3404 82321 38002 10490 5564 83211 25272 19898 Quantity August 0 0 0 0 Elec_MMBtuJul 57398 24718 10772 3927 71818 39818 50000 4413 72511 33473 9240 4901 78690 23899 18817 Quantity September 0 0 0 0 Elec_MMBtuAug 84959 36587 15944 5812 104145 57742 72506 6399 84765 39130 10802 5729 97841 29716 23396 Quantity October 0 0 0 0 Elec_MMBtuSep 73182 31515 13734 5006 136320 75581 94907 8376 103476 47768 13186 6994 151302 45952 36180 Quantity November 0 0 0 0 Elec_MMBtuOct 185282 79790 34771 12675 126255 70000 87899 7758 104361 48176 13299 7054 110174 33461 26345 Quantity December 0 0 0 0 Elec_MMBtuNov 140353 60442 26340 9601 105334 58401 73334 6472 130350 60174 16611 8810 113446 34455 27128 Elec_Quantity January 0 0 0 0 Elec_MMBtuDec 140477 60495 26363 9610 116230 64441 80919 7142 135428 62518 17258 9154 129464 39320 30958 Elec_Quantity February 0 0 0 0 Netgen_Jan 16791.748 7231.235 3151.255 1148.708 11807.727 6546.59 8220.562 725.534 12482.947 5762.515 1590.718 843.735 12314.597 3740.107 2944.713 Elec_Quantity March 0 0 0 0 Netgen_Feb 7704.386 3317.833 1445.859 527.05 9739.813 5400.071 6780.876 598.469 10495.246 4844.931 1337.423 709.384 11114.167 3375.521 2657.662 Elec_Quantity April 0 0 0 0 Netgen_Mar 6879.971 2962.805 1291.143 470.652 12440.312 6897.316 8660.969 764.403 8675.723 4004.982 1105.558 586.4 10053.585 3053.408 2404.051 Elec_Quantity May 0 0 0 0 Netgen_Apr 11627.741 5007.395 2182.143 795.443 7813.513 4332.067 5439.783 480.106 10506.509 4850.13 1338.858 710.145 10776.271 3272.897 2576.863 Elec_Quantity June 0 0 0 0 Netgen_May 12586.426 5420.245 2362.056 861.026 5180.728 2872.365 3606.833 318.333 10199.526 4708.417 1299.739 689.396 9422.357 2861.695 2253.11 Elec_Quantity July 0 0 0 0 Netgen_Jun 7435.847 3202.189 1395.463 508.679 6000.282 3326.752 4177.408 368.691 8833.704 4077.911 1125.69 597.078 8749.89 2657.458 2092.307 Elec_Quantity August 0 0 0 0 Netgen_Jul 6230.106 2682.946 1169.185 426.196 7779.259 4313.075 5415.935 478.002 7780.953 3591.929 991.537 525.922 8274.473 2513.068 1978.623 Elec_Quantity September 0 0 0 0 Netgen_Aug 9221.631 3971.223 1730.595 630.843 11280.916 6254.509 7853.796 693.163 9095.941 4198.968 1159.107 614.803 10288.216 3124.668 2460.157 Elec_Quantity October 0 0 0 0 Netgen_Sep 7943.385 3420.756 1490.711 543.4 14766.082 8186.798 10280.174 907.311 11103.732 5125.827 1414.963 750.512 15909.737 4831.999 3804.396 Elec_Quantity November 0 0 0 0 Netgen_Oct 20110.89 8660.597 3774.15 1375.767 13675.828 7582.326 9521.137 840.32 11198.704 5169.668 1427.065 756.931 11585.094 3518.547 2770.271 Elec_Quantity December 0 0 0 0 Netgen_Nov 15234.221 6560.497 2858.96 1042.159 11409.685 6325.903 7943.445 701.076 13987.574 6457.097 1782.454 945.433 11929.143 3623.04 2852.542 MMBtuPer_Unit January 0 0 0 0 Netgen_Dec 15247.648 6566.279 2861.48 1043.077 12589.855 6980.228 8765.082 773.592 14532.441 6708.625 1851.888 982.261 13613.47 4134.592 3255.305 MMBtuPer_Unit February 0 0 0 0 Net Generation (Megawatthours) 137014 59004 25713 9373 124484 69018 86666 7649 128893 59501 16425 8712 134031 40707 32050 MMBtuPer_Unit March 0 0 0 0 MMBtuPer_Unit April 0 0 0 0 MMBtuPer_Unit May 0 0 0 0 MMBtuPer_Unit June 0 0 0 0 MMBtuPer_Unit July 0 0 0 0 MMBtuPer_Unit August 0 0 0 0 MMBtuPer_Unit September 0 0 0 0 MMBtuPer_Unit October 0 0 0 0 MMBtuPer_Unit November 0 0 0 0 MMBtuPer_Unit December 0 0 0 0 Tot_MMBtu January 0 0 0 0 Tot_MMBtu February 100828 46434 49461 5785 Tot_MMBtu March 99916 46014 49014 5733 Tot_MMBtu April 101546 46765 49813 5826 Tot_MMBtu May 107165 49352 52570 6149 Tot_MMBtu June 120036 55280 58884 6887 Tot_MMBtu July 109340 50354 53637 6273 Tot_MMBtu August 93235 42937 45737 5349 Tot_MMBtu September 80845 37231 39659 4638 Tot_MMBtu October 69129 31836 33911 3966 Tot_MMBtu November 68245 31428 33477 3916 Tot_MMBtu December 79639 36676 39067 4569 Elec_MMBtu January 82191 37851 40319 4716 Elec_MMBtu February 100828 46434 49461 5785 Elec_MMBtu March 99916 46014 49014 5733 Elec_MMBtu April 101546 46765 49813 5826 Elec_MMBtu May 107165 49352 52570 6149 Elec_MMBtu June 120036 55280 58884 6887 Elec_MMBtu July 109340 50354 53637 6273 Elec_MMBtu August 93235 42937 45737 5349 Elec_MMBtu September 80845 37231 39659 4638 Elec_MMBtu October 69129 31836 33911 3966 Elec_MMBtu November 68245 31428 33477 3916 Elec_MMBtu December 79639 36676 39067 4569 Netgen January 82191 37851 40319 4716 Netgen February 11058.086 5092.546 5424.554 634.46 Netgen March 10958.057 5046.48 5375.485 628.721 Netgen April 11136.875 5128.83 5463.204 638.981 Netgen May 11753.103 5412.62 5765.495 674.337 Netgen June 13164.716 6062.705 6457.963 755.329 Netgen July 11991.688 5522.494 5882.533 688.026 Netgen August 10225.421 4709.081 5016.089 586.686 Netgen September 8866.51 4083.266 4349.474 508.718 Netgen October 7581.623 3491.541 3719.172 434.997 Netgen November 7484.6 3446.859 3671.577 429.431 Netgen December 8734.221 4022.343 4284.58 501.128 Total Fuel Consumption Quantity 9014.1 4151.235 4421.874 517.186 Electric Fuel Consumption Quantity 0 0 0 0 Total Fuel Consumption MMBtu 0 0 0 0 Elec Fuel Consumption MMBtu 1112115 512158 545549 63807 Net Generation (Megawatthours) 1112115 512158 545549 63807 YEAR 121969 56170 59832 6998 2018 2018 2018 2018 year 2008 2008 2008 2009 2009 2009 2010 2010 2010 2011 2011 2011 2012 2012 2012 2013 2013 2013 utility__name Chugach Electric Assn Inc Kodiak Electric Assn Inc Sitka, City & Borough of Chugach Electric Assn Inc Kodiak Electric Assn Inc Sitka, City & Borough of Chugach Electric Assn Inc Kodiak Electric Assn Inc Sitka, City & Borough of Chugach Electric Assn Inc Kodiak Electric Assn Inc Sitka, City & Borough of Chugach Electric Assn Inc Kodiak Electric Assn Inc Sitka, City & Borough of Chugach Electric Assn Inc Kodiak Electric Assn Inc Sitka, City & Borough of utility__regulatory_status__name Regulated Regulated Not regulated Regulated Regulated Not regulated Regulated Regulated Not regulated Regulated Regulated Not regulated Regulated Regulated Not regulated Regulated Regulated Not regulated utility__certificate True True True True True True True True True True True True True True True True True True utility__utility_type__name Electric Co-op Electric Co-op Public Electric Utility Electric Co-op Electric Co-op Public Electric Utility Electric Co-op Electric Co-op Public Electric Utility Electric Co-op Electric Co-op Public Electric Utility Electric Co-op Electric Co-op Public Electric Utility Electric Co-op Electric Co-op Public Electric Utility utility__eia_operator_id 3522 10433 17271 3522 10433 17271 3522 10433 17271 3522 10433 17271 3522 10433 17271 3522 10433 17271 utility__pce_id plant__name Cooper Lake Terror Lake Blue Lake Cooper Lake Terror Lake Blue Lake Cooper Lake Terror Lake Blue Lake Cooper Lake Terror Lake Blue Lake Cooper Lake Terror Lake Blue Lake Cooper Lake Terror Lake Blue Lake plant__pce_status__name PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible PCE Ineligible plant__intertied True True False True True False True True False True True False True True False True True False plant__akeps_region__abbreviation SC SC SE SC SC SE SC SC SE SC SC SE SC SC SE SC SC SE plant__akeps_region__name Southcentral Southcentral Southeast Southcentral Southcentral Southeast Southcentral Southcentral Southeast Southcentral Southcentral Southeast Southcentral Southcentral Southeast Southcentral Southcentral Southeast plant__eia_plant_id 6291 71 93 6291 71 93 6291 71 93 6291 71 93 6291 71 93 6291 71 93 primary_community__name Anchorage Kodiak Sitka Anchorage Kodiak Sitka Anchorage Kodiak Sitka Anchorage Kodiak Sitka Anchorage Kodiak Sitka Anchorage Kodiak Sitka primary_community__gnis_feature_id 1398242 1404875 1414736 1398242 1404875 1414736 1398242 1404875 1414736 1398242 1404875 1414736 1398242 1404875 1414736 1398242 1404875 1414736 primary_community__census_code 3000 40950 70540 3000 40950 70540 3000 40950 70540 3000 40950 70540 3000 40950 70540 3000 40950 70540 primary_community__census_area__name Anchorage Municipality Kodiak Island Borough Sitka City and Borough Anchorage Municipality Kodiak Island Borough Sitka City and Borough Anchorage Municipality Kodiak Island Borough Sitka City and Borough Anchorage Municipality Kodiak Island Borough Sitka City and Borough Anchorage Municipality Kodiak Island Borough Sitka City and Borough Anchorage Municipality Kodiak Island Borough Sitka City and Borough primary_community__census_area__gnis_feature_id 1416061 1419974 1419981 1416061 1419974 1419981 1416061 1419974 1419981 1416061 1419974 1419981 1416061 1419974 1419981 1416061 1419974 1419981 primary_community__census_area__census_code 99020 99150 99220 99020 99150 99220 99020 99150 99220 99020 99150 99220 99020 99150 99220 99020 99150 99220 primary_community__census_area__county_code 20 150 220 20 150 220 20 150 220 20 150 220 20 150 220 20 150 220 primary_community__census_area__historical False False False False False False False False False False False False False False False False False False primary_community__census_area__notes primary_community__alaska_native_regional_corporation__name Koniag, Incorporated Sealaska Corporation Koniag, Incorporated Sealaska Corporation Koniag, Incorporated Sealaska Corporation Koniag, Incorporated Sealaska Corporation Koniag, Incorporated Sealaska Corporation Koniag, Incorporated Sealaska Corporation primary_community__latitude 61.2180556 57.79 57.0530556 61.2180556 57.79 57.0530556 61.2180556 57.79 57.0530556 61.2180556 57.79 57.0530556 61.2180556 57.79 57.0530556 61.2180556 57.79 57.0530556 primary_community__longitude -149.9002778 -152.4072222 -135.33 -149.9002778 -152.4072222 -135.33 -149.9002778 -152.4072222 -135.33 -149.9002778 -152.4072222 -135.33 -149.9002778 -152.4072222 -135.33 -149.9002778 -152.4072222 -135.33 primary_community__aea_energy_region__name Railbelt Kodiak Southeast Railbelt Kodiak Southeast Railbelt Kodiak Southeast Railbelt Kodiak Southeast Railbelt Kodiak Southeast Railbelt Kodiak Southeast primary_community__dcra_community_id e6c4e976-7e27-4809-a3e4-f168d67f1726 d91d5e68-90a3-45f5-ab73-9f89f2652c5a 61300339-a614-43fb-a30f-41604e5e0c1c e6c4e976-7e27-4809-a3e4-f168d67f1726 d91d5e68-90a3-45f5-ab73-9f89f2652c5a 61300339-a614-43fb-a30f-41604e5e0c1c e6c4e976-7e27-4809-a3e4-f168d67f1726 d91d5e68-90a3-45f5-ab73-9f89f2652c5a 61300339-a614-43fb-a30f-41604e5e0c1c e6c4e976-7e27-4809-a3e4-f168d67f1726 d91d5e68-90a3-45f5-ab73-9f89f2652c5a 61300339-a614-43fb-a30f-41604e5e0c1c e6c4e976-7e27-4809-a3e4-f168d67f1726 d91d5e68-90a3-45f5-ab73-9f89f2652c5a 61300339-a614-43fb-a30f-41604e5e0c1c e6c4e976-7e27-4809-a3e4-f168d67f1726 d91d5e68-90a3-45f5-ab73-9f89f2652c5a 61300339-a614-43fb-a30f-41604e5e0c1c service_area Anchorage, Beluga, Cooper Landing, Girdwood, Hope, Moose Pass, Point Possession, Sunrise, Tyonek, Whittier Chiniak, Kodiak, Kodiak Station, Port Lions, Womens Bay, Woody Island Sitka Anchorage, Beluga, Cooper Landing, Girdwood, Hope, Moose Pass, Point Possession, Sunrise, Tyonek, Whittier Chiniak, Kodiak, Kodiak Station, Port Lions, Womens Bay, Woody Island Sitka Anchorage, Beluga, Cooper Landing, Girdwood, Hope, Moose Pass, Point Possession, Sunrise, Tyonek, Whittier Chiniak, Kodiak, Kodiak Station, Port Lions, Womens Bay, Woody Island Sitka Anchorage, Beluga, Cooper Landing, Girdwood, Hope, Moose Pass, Point Possession, Sunrise, Tyonek, Whittier Chiniak, Kodiak, Kodiak Station, Port Lions, Womens Bay, Woody Island Sitka Anchorage, Beluga, Cooper Landing, Girdwood, Hope, Moose Pass, Point Possession, Sunrise, Tyonek, Whittier Chiniak, Kodiak, Kodiak Station, Port Lions, Womens Bay, Woody Island Sitka Anchorage, Beluga, Cooper Landing, Girdwood, Hope, Moose Pass, Point Possession, Sunrise, Tyonek, Whittier Chiniak, Kodiak, Kodiak Station, Port Lions, Womens Bay, Woody Island Sitka aea_energy_region__name Railbelt Kodiak Southeast Railbelt Kodiak Southeast Railbelt Kodiak Southeast Railbelt Kodiak Southeast Railbelt Kodiak Southeast Railbelt Kodiak Southeast net_generation_oil 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 net_generation_gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 net_generation_coal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 net_generation_hydro 6663 120879 55760 33262 98551 58422 45390 123964 58422 28759 114186 56154 77589 131121 55672 35928 119142 52463 net_generation_wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 net_generation_other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 oil_used 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 gas_used 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 coal_used 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 source eia eia eia eia eia eia eia eia eia eia eia eia eia eia eia eia eia eia notes In addition to Anchorage, the CEA service area includes eight other communities. The KEA service area includes the communities of Port Lions, Chiniak, Womens Bay and Woody Island. In addition to Anchorage, the CEA service area includes eight other communities. The KEA service area includes the communities of Port Lions, Chiniak, Womens Bay and Woody Island. In addition to Anchorage, the CEA service area includes eight other communities. The KEA service area includes the communities of Port Lions, Chiniak, Womens Bay and Woody Island. In addition to Anchorage, the CEA service area includes eight other communities. The KEA service area includes the communities of Port Lions, Chiniak, Womens Bay and Woody Island. In addition to Anchorage, the CEA service area includes eight other communities. The KEA service area includes the communities of Port Lions, Chiniak, Womens Bay and Woody Island. In addition to Anchorage, the CEA service area includes eight other communities. The KEA service area includes the communities of Port Lions, Chiniak, Womens Bay and Woody Island. YEAR 2018 2018 2018 2017 2017 2017 2016 2016 2016 2015 2015 2015 2014 2014 2014 year 2008 2008 2008 2009 2009 2009 2010 2010 2010 2011 2011 2011 2012 2012 2012 2013 2013 2013 year 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Plant Id 93 313 6801 93 313 6801 93 313 6801 93 313 6801 93 313 6801 utility__name Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of Sitka, City & Borough of plant__name Blue Lake Blue Lake Blue Lake Blue Lake Blue Lake Blue Lake Blue Lake Blue Lake Blue Lake Blue Lake Blue Lake Green Lake Green Lake Green Lake Green Lake Green Lake Green Lake Green Lake Green Lake Green Lake Green Lake Green Lake Jarvis Street Jarvis Street Jarvis Street Jarvis Street Jarvis Street Jarvis Street Jarvis Street Jarvis Street Jarvis Street Jarvis Street Jarvis Street Nuclear Unit Id . . . N N N N N N N N N N N N utility__regulatory_status__name Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated net gen 55760 58422 58422 56154 55672 52463 40707 59501 69018 59004 56170 61118 58101 58101 58996 57966 60781 70792 49511 35983 54587 52270 -111 -770 -169 1386 1820 151 251 -270 1099 -545 -629 Plant Name Blue Lake Hydro Green Lake Jarvis Street Blue Lake Hydro Green Lake Jarvis Street Blue Lake Hydro Green Lake Jarvis Street Blue Lake Hydro Green Lake Jarvis Street Blue Lake Hydro Green Lake Jarvis Street utility__certificate True True True True True True True True True True True True True True True True True True Oil 0 0 0 0 0 0 0 0 0 0 0 0 80682 28308 68628 161028 180936 71820 89376 68880 153216 42588 44688 Operator Name City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) City & Borough of Sitka - (AK) utility__utility_type__name Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Net Generation (Megawatthours) 56170 52270 -629 6566.279 6074.732 -47.208 6980.228 3639.189 169.982 59501 49511 -270 40707 70792 251 utility__eia_operator_id 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 Operator Id 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 17271 utility__pce_id Plant State AK AK AK HY HY IC HY HY IC AK AK AK AK AK AK plant__name Blue Lake Green Lake Jarvis Street Blue Lake Green Lake Jarvis Street Blue Lake Green Lake Jarvis Street Blue Lake Green Lake Jarvis Street Blue Lake Green Lake Jarvis Street Blue Lake Green Lake Jarvis Street Row Labels 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Grand Total Sum of net gen Row Labels 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Grand Total Census Region PACN PACN PACN WAT WAT DFO WAT WAT DFO HY HY IC HY HY IC net gen 55760 61118 -111 58422 58101 -770 58422 58101 -169 56154 58996 1386 55672 57966 1820 52463 60781 151 Sum of net gen 116767 115753 116354 116536 115458 113395 111750 108742 106100 113046 107811 1241712 Column Labels Blue Lake 55760 58422 58422 56154 55672 52463 40707 59501 69018 59004 56170 621293 NERC Region ASCC ASCC ASCC barrels barrels WAT WAT DFO WAT WAT DFO net_generation_oil 0 0 -111 0 0 -770 0 0 -169 0 0 1386 0 0 1820 0 0 151 Sum of Oil 80682 28308 68628 161028 180936 71820 89376 68880 153216 42588 44688 990150 Green Lake 61118 58101 58101 58996 57966 60781 70792 49511 35983 54587 52270 618206 Reserved 0 0 141 0 0 297 barrels barrels net_generation_gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Jarvis Street -111 -770 -169 1386 1820 151 251 -270 1099 -545 -629 2213 NAICS Code 22 22 22 0 0 101 0 0 328 0 0 170 0 0 221 net_generation_coal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Grand Total 116767 115753 116354 116536 115458 113395 111750 108742 106100 113046 107811 1241712 EIA Sector Number 1 1 1 0 0 110 0 0 311 0 0 149 0 0 209 net_generation_hydro 55760 61118 0 58422 58101 0 58422 58101 0 56154 58996 0 55672 57966 0 52463 60781 0 Sector Name Electric Utility Electric Utility Electric Utility 0 0 64 0 0 254 0 0 150 0 0 204 net_generation_wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reported Prime Mover HY HY IC 0 0 63 0 0 232 0 0 155 0 0 192 net_generation_other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reported Fuel Type Code WAT WAT DFO 0 0 65 0 0 233 0 0 125 0 0 162 oil_used 0 0 80682 0 0 28308 0 0 68628 0 0 161028 0 0 180936 0 0 71820 AER Fuel Type Code HYC HYC DFO 0 0 81 0 0 195 0 0 124 0 0 97 gas_used 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reserved 0 0 81 0 0 256 0 0 129 0 0 171 coal_used 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Reserved 0 0 70 0 0 261 0 0 147 0 0 137 source eia eia eia eia eia eia eia eia eia eia eia eia eia eia eia eia eia eia Physical Unit Label barrels 0 0 70 0 0 299 0 0 132 0 0 162 net gen 55760 61118 -111 58422 58101 -770 58422 58101 -169 56154 58996 1386 55672 57966 1820 52463 60781 151 0 0 80 0 0 418 0 0 151 0 0 214 Netgen January 5092.546 4738.959 -50.398 0 0 88 0 0 564 0 0 106 0 0 156 Electricity Net Generation (MWh) Netgen February 5046.48 4696.092 -47.003 66621 61634 818 60438 31510 1723 0 0 102 0 0 203 Netgen March 5128.83 4772.725 -47.009 30567 28279 586 49853 25991 1902 53701 44685 986 35568 61856 1282 Netgen April 5412.62 5036.81 -47.485 27296 25253 638 63676 33198 1804 45150 37569 864 32101 55826 1212 Netgen May 6062.705 5641.759 -54.333 46133 42680 371 39994 20851 1473 37322 31056 870 29038 50499 1183 Netgen June 5522.494 5139.056 -50.726 49937 46198 365 26518 13825 1346 45198 37610 899 31125 54129 1114 Netgen July 4709.081 4382.12 -54.659 29502 27293 377 30713 16012 1351 43878 36511 725 27215 47328 940 Netgen August 4083.266 3799.756 -55.816 24718 22868 470 39818 20760 1131 38002 31622 719 25272 43950 563 Netgen September 3491.541 3249.116 -56.817 36587 33848 470 57742 30104 1485 33473 27853 748 23899 41562 992 Netgen October 3446.859 3207.537 -59.657 31515 29156 406 75581 39404 1514 39130 32560 853 29716 51677 795 Netgen November 4022.343 3743.064 -53.677 79790 73817 406 70000 36495 1734 47768 39748 766 45952 79914 940 Netgen December 4151.235 3863.006 -51.42 60442 55917 464 58401 30448 2424 48176 40088 876 33461 58191 1241 60495 55967 510 64441 33597 3271 60174 50071 615 34455 59920 905 7231.235 6689.908 -75.861 6546.59 3413.109 89.11 62518 52021 592 39320 68380 1177 3317.833 3069.462 -54.115 5400.071 2815.363 98.889 5762.515 4795.01 -27.844 3740.107 6504.279 26.02 2962.805 2741.012 -59.116 6897.316 3595.962 93.583 4844.931 4031.484 -24.556 3375.521 5870.24 24.688 5007.395 4632.545 -34.257 4332.067 2258.552 76.639 4004.982 3332.561 -24.702 3053.408 5310.065 24.1 5420.245 5014.489 -33.828 2872.365 1497.527 69.909 4850.13 4035.811 -25.583 3272.897 5691.771 22.644 3202.189 2962.475 -34.906 3326.752 1734.425 70.32 4708.417 3917.891 -20.56 2861.695 4976.666 19.119 Total Fuel Consumption Quantity 0 0 1064 2682.946 2482.103 -43.749 4313.075 2248.651 58.826 4077.911 3393.245 -20.483 2657.458 4621.484 11.396 Year-To-Date Electric Fuel Consumption Quantity 0 0 1064 3971.223 3673.94 -43.681 6254.509 3260.83 77.096 3591.929 2988.857 -21.286 2513.068 4370.381 20.147 Total Fuel Consumption MMBtu 512158 476598 6173 3420.756 3164.681 -37.54 8186.798 4268.243 78.556 4198.968 3493.977 -24.166 3124.668 5433.992 16.209 Elec Fuel Consumption MMBtu 512158 476598 6173 8660.597 8012.27 -37.519 7582.326 3953.097 90.209 5125.827 4265.219 -21.765 4831.999 8403.146 19.071 6560.497 6069.383 -43.22 6325.903 3298.052 125.881 5169.668 4301.7 -24.9 3518.547 6118.972 25.21 6457.097 5372.974 -17.411 3623.04 6300.691 18.427 6708.625 5582.271 -16.744 4134.592 7190.313 23.969 0 0 1640 0 0 2128 0 0 1640 387122 673232 12344 554490 461394 9513 387122 673232 12344 id 54 58 59 62 55 56 57 49 50 60 61 328 329 470 471 472 473 474 671 590 668 669 670 475 927 928 929 930 931 932 933 1351 1352 1353 1354 1355 1356 1357 1358 1359 1360 1361 1362 1705 1706 1707 2031 2213 2214 2215 2216 2217 2099 2100 2101 2323 2324 2325 2326 2327 2328 2329 2330 2331 3188 3189 3190 3416 3417 3418 3419 3420 3421 3422 3423 3424 422 423 424 425 426 433 432 431 430 429 428 427 421 420 419 418 417 416 415 414 413 412 411 410 581 582 583 584 585 586 587 588 589 949 950 951 995 996 997 998 999 1000 1001 1002 1003 1374 1375 1376 1852 1853 1854 1855 1865 1866 1867 1877 1878 2111 2112 2113 2437 2438 2439 2440 2441 2442 2443 2444 2445 3200 3201 3202 286 287 288 289 290 291 292 293 294 295 296 297 274 275 276 277 278 279 280 281 282 283 284 285 336 337 338 339 340 341 342 343 344 554 555 556 610 611 612 613 614 615 616 617 618 966 967 968 1116 1117 1118 1119 1120 1121 1122 1123 1124 2181 1727 1728 1729 1730 1731 1732 1733 1734 1735 2179 2180 2746 2747 2748 2749 2750 2751 2752 2753 2754 2755 2756 3184 3854 3855 3856 3857 3858 3859 3860 3861 3862 3863 3864 3865 2150 2149 1745 1746 1747 1748 1749 1750 1751 2128 2129 2130 2586 2587 2588 2589 2590 2591 2592 2593 2594 2595 2596 2597 3878 3879 3880 3881 3882 3883 3884 3885 3886 3887 3888 3889 268 269 270 271 272 273 345 346 347 348 349 350 351 352 353 458 459 460 559 560 561 619 620 621 622 623 624 914 915 916 1301 1302 1303 1304 1305 1306 1307 1308 1309 1402 1403 1404 1586 1587 1588 1589 1590 1591 1592 1593 1594 2245 2246 2247 2610 2611 2612 2613 2614 2615 2616 2617 2618 2619 2620 2621 4400 4401 4402 4403 4404 4405 4406 4407 4408 4409 4410 4411 1051 1052 1053 1054 994 1044 1045 1046 1047 1048 1049 1050 1377 1378 1379 1380 354 400 402 403 404 405 434 665 666 667 562 563 564 565 566 567 568 569 570 571 652 653 923 924 925 926 984 985 986 1088 987 988 989 990 1394 1395 1396 1532 1533 1534 1535 1536 1537 1538 1539 1540 2108 2109 2110 2269 2270 2271 2272 2273 2274 2275 2276 2277 3278 3279 3280 3712 3713 3714 3715 3716 3717 3718 3719 3720 3721 3722 3723 451 452 453 406 407 408 409 592 593 594 595 596 597 598 599 672 673 940 1095 1094 1093 1092 1091 1090 1089 992 993 3143 3144 3145 3146 3147 3148 3149 3150 3151 3152 3153 3154 3988 3989 3990 3991 3992 3993 3994 3995 476 477 478 479 480 481 482 483 484 485 486 487 600 649 650 662 663 664 763 776 789 937 938 939 1096 1097 1098 1099 1100 1101 1102 1103 1104 1105 1466 1467 1708 1709 1710 1711 1712 1713 1714 1715 1716 3331 3332 3333 3334 3335 3336 3337 3338 3339 3340 3341 3342 1405 1406 1407 1408 1604 1605 1606 1607 1608 1609 1610 1611 1612 2131 2132 2133 2622 2623 2624 2625 2626 2627 2628 2629 2630 2631 2632 2633 3544 3545 3546 3547 3548 3549 3550 3551 3552 3553 3554 3555 377 378 379 380 381 382 383 384 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180 181 182 385 386 387 531 532 533 838 839 840 841 842 843 844 845 846 847 848 849 1238 1239 1240 1241 1242 1243 1244 1245 1246 1445 1446 1447 1521 1522 1523 1524 1525 1526 1527 1528 1529 1530 1531 2236 2975 2976 2977 2978 2979 2980 2981 2982 2983 3281 3282 3283 442 443 444 445 331 332 333 334 335 488 490 491 489 645 646 647 648 711 712 713 714 944 945 946 1022 1023 1024 1025 1026 1027 1028 1388 1389 1699 1700 1701 1702 2161 2162 2163 2164 2165 1703 1704 2166 2336 2337 2338 2339 3343 3344 3345 3346 3347 3348 3349 3350 3425 3426 3427 3428 3429 3430 3431 3432 3433 3965 3966 3967 401 238 239 240 241 242 243 244 245 246 247 248 249 250 251 252 253 254 255 256 257 258 259 260 261 262 263 264 265 266 267 397 398 399 551 552 553 898 899 900 901 902 903 904 905 906 907 908 909 1283 1284 1285 1286 1287 1288 1289 1290 1291 2242 2243 2244 2059 2060 2061 2062 2063 2064 2065 2066 2067 2239 2240 2241 3123 3124 3125 3126 3127 3128 3129 3170 3171 3383 3384 3385 4032 4033 4034 4035 4036 4037 4038 4039 4040 4041 4042 4043 2937 2938 2939 2940 2941 2942 2943 2944 2945 2946 3273 3274 4258 4259 4260 4261 4262 4263 4264 4265 4266 4267 4383 4268 601 602 603 604 605 606 607 608 609 969 970 971 1342 1343 1344 1345 1346 1347 1348 1349 1350 1363 1364 1365 1764 1765 1766 1767 1768 1769 1770 1771 1772 1773 1774 1775 2634 2635 2636 2637 2638 2639 2640 2641 2642 2643 2644 2645 3568 3569 3570 3571 3572 3573 3574 3575 3576 2352 2353 2354 2355 2356 2357 2358 2359 2360 2361 2362 2363 63 65 66 67 68 69 70 71 72 73 74 330 64 298 299 300 301 302 461 462 466 467 468 469 625 626 627 628 629 630 631 632 633 952 965 953 1004 1005 1006 1007 1008 1009 1381 1382 1469 1383 1384 1385 1908 1909 1922 1923 1924 1925 1926 1927 1928 2114 2115 2116 2455 2456 2457 2458 2459 2460 2461 2462 2463 3102 3103 3104 1777 1726 1736 1778 2167 2168 2169 2170 1779 1780 1781 1737 2758 2759 2760 2761 2762 2763 2764 2765 2766 2767 2768 2769 683 684 685 686 687 688 689 690 691 934 935 936 1106 1107 1108 1109 1110 1111 1112 1113 1114 1115 1412 1413 1502 1503 1504 1506 1507 1508 1509 1510 1511 2044 2045 2046 2715 2716 2717 2718 2719 2720 2721 2722 2723 3401 3402 3403 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 201 202 388 389 390 534 535 536 850 851 852 853 854 855 856 857 858 859 860 861 1247 1248 1249 1250 1251 1252 1253 1254 1255 1448 1449 1450 1783 1784 1785 1786 1787 1788 1789 1790 1791 2068 2069 2070 3106 2958 2959 2960 2961 2962 2963 2964 2965 3284 3285 3286 4008 4009 4010 4011 4012 4013 4014 4015 4016 4017 4018 4019 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 394 395 396 548 549 550 874 875 876 877 878 879 880 881 882 883 884 885 1274 1275 1276 1277 1278 1279 1280 1281 1282 1454 1455 1456 1795 1796 1797 1798 1799 1800 1801 1802 1803 2071 2072 2073 3108 2819 2820 2821 2822 2823 2824 2825 2826 3287 3288 3289 3736 3737 3738 3739 3740 3741 3742 3743 3744 3745 3746 3747 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 374 375 376 528 529 530 814 815 816 817 818 819 820 821 822 823 824 825 1220 1221 1222 1223 1224 1225 1226 1227 1228 1463 1464 1465 1899 1900 1901 1902 1903 1904 1905 1906 1907 2074 2075 2076 3118 2827 2828 2829 2830 2831 2832 2833 2834 3172 3173 3174 4281 4282 4283 4284 4285 4286 4287 4288 4289 4290 4291 4292 522 523 524 525 526 527 557 558 790 791 792 793 794 795 796 797 798 799 800 801 1211 1212 1213 1214 1215 1216 1217 1218 1219 1808 1809 1810 1811 1812 1813 1814 1815 1816 2002 2003 2004 2835 2836 2837 2838 2839 2840 2841 2842 2843 3290 3291 3292 4056 4057 4058 4059 4060 4061 4062 4063 4064 4065 4066 4067 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 355 356 357 358 727 728 729 730 731 732 733 734 735 736 737 738 1157 1158 1159 1160 1161 1162 1163 1164 1165 1482 1483 1484 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 3155 3156 3157 3158 3159 3160 3161 3162 3163 3164 3165 3166 3760 3761 3762 3763 3764 3765 3766 3767 3768 3769 3770 3771 498 499 500 501 502 503 504 505 506 507 508 509 510 511 512 513 514 515 108 109 110 111 112 113 114 115 116 117 118 119 120 121 122 362 363 364 365 366 367 516 517 518 764 765 766 767 768 769 770 771 772 773 774 775 1193 1194 1195 1196 1197 1198 1199 1200 1201 1436 1437 1438 1910 1911 1912 1913 1914 1915 1916 1917 1918 1919 1920 1921 2920 2921 2922 2923 2924 2925 2926 2927 2928 3404 3405 3406 4302 4303 4304 4305 4306 4307 4308 4309 4310 4415 4416 4417 304 305 306 303 307 308 309 310 311 312 313 314 315 316 317 318 319 320 321 322 454 455 456 457 954 955 956 957 958 959 960 961 962 963 964 1125 1126 1127 1128 1129 1130 1131 1372 1468 1929 1930 1931 1932 1933 2182 2183 2184 1934 2029 2117 2118 3070 3071 3072 3073 3074 3075 3076 3077 3078 3079 3080 3081 802 803 804 805 806 807 808 809 810 811 812 813 1132 1133 1134 1135 1136 1137 1138 1139 1140 1369 1370 1371 1983 1984 1985 1986 1987 1988 1989 1990 1991 2230 2237 2238 3095 3096 3097 3098 3099 3100 3101 3168 3169 3395 3396 3397 4080 4081 4082 4083 4084 4085 4086 4087 4088 4089 4090 4091 692 693 694 695 696 697 698 699 700 701 702 703 1319 1320 1321 1322 1323 1324 1325 1326 1327 1328 1428 1429 2218 2219 2220 2221 2222 2223 2224 2225 2226 2227 2228 2229 3084 3085 3086 3087 3088 3089 3090 3091 3092 3093 3094 3167 495 496 497 751 752 753 754 755 756 757 758 759 760 761 762 1175 1176 1177 1178 1179 1180 1181 1182 1183 1433 1434 1435 1825 1826 1827 1828 1829 1830 1831 1832 1833 2077 2078 2185 2929 2930 2931 2932 2933 2934 2935 2936 3300 3301 3302 3303 4323 4324 4325 4326 4327 4328 4329 4330 4331 4332 4333 4334 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 368 369 370 371 372 373 519 520 521 777 778 779 780 781 782 783 784 785 786 787 788 1202 1203 1204 1205 1206 1207 1208 1209 1210 1439 1440 1441 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2079 2080 2919 2844 2845 2846 2847 2848 2849 2850 2851 3398 3399 3400 3926 3927 3928 3929 3930 3931 3932 3933 3934 3935 3936 3937 463 464 465 674 675 676 677 678 679 680 681 682 917 918 919 1078 1079 1080 1081 1082 1083 1084 1085 1086 1087 1397 1398 1494 1495 1496 1497 1498 1499 1500 1501 2047 2105 2106 2107 2724 2725 2726 2727 2728 2729 2730 2731 2732 2733 4199 4200 4201 4202 4203 4204 4205 4206 4207 4208 4209 4210 325 323 326 327 324 446 447 448 449 450 591 634 635 704 705 706 707 636 708 911 912 913 1029 1030 1031 1032 1153 1154 1155 1035 1033 1034 1156 1390 2030 1776 1782 1792 2175 2176 2177 2178 1793 1794 2211 2212 2388 2389 2390 2391 2392 2393 2394 2395 2396 2397 2398 2399 4347 4348 4349 4350 4351 4352 4353 4354 4355 4356 4357 4358 991 1036 1037 1038 1039 1150 1040 1041 1042 1043 1151 1152 1804 1805 1806 1807 2171 2172 2173 2174 1817 1818 1819 1820 2405 2406 2407 2408 3139 3140 3141 3142 2409 3316 3317 3318 1417 1418 1419 1420 1421 1422 1423 1427 1424 1425 1426 1690 1691 1692 1693 1694 1695 1696 1697 1698 2232 2233 2234 2646 2647 2648 2649 2650 2651 2652 2653 2654 2655 2656 2657 3592 3593 3594 3595 3596 3597 3598 3599 3600 3601 3602 3603 2152 2151 1637 1638 1639 1640 1641 1642 2134 2135 2136 2137 2658 2659 2660 2661 2662 2663 2664 2665 2666 2667 2668 2669 3902 3903 3904 3905 3906 3907 3908 3909 3910 3911 3912 3913 1067 1068 1329 1935 1936 1937 1938 1939 1940 1941 1942 1943 2119 2120 2121 2474 2475 2476 2477 2478 2479 2480 2481 2482 2483 3002 3003 886 887 888 889 890 891 892 893 894 895 896 897 1141 1142 1143 1144 1145 1146 1147 1148 1149 1366 1367 1368 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2231 3061 3062 3063 3064 3065 3066 3067 3068 3069 3389 3390 3391 4104 4105 4106 4107 4108 4109 4110 4111 4112 4113 4114 4115 2494 2495 2496 2497 2498 2499 2500 2501 2502 2503 3363 3364 99 100 101 102 103 104 105 106 107 359 360 361 492 493 494 739 740 741 742 743 744 745 746 747 748 749 750 1166 1167 1168 1169 1170 1171 1172 1173 1174 1430 1431 1432 1834 1835 1836 1837 1838 1839 1840 1841 1842 2081 2082 2083 3120 2860 2861 2862 2863 2864 2865 2866 2867 3304 3305 3306 4128 4129 4130 4131 4132 4133 4134 4135 4136 4137 4138 4139 540 541 542 543 544 545 546 547 862 863 864 865 866 867 868 869 870 871 872 873 1265 1266 1267 1268 1269 1270 1271 1272 1273 1451 1452 1453 1843 1844 1845 1846 1847 1848 1849 1850 1851 2084 2085 2086 3122 2868 2869 2870 2871 2872 2873 2874 2875 3178 3179 3180 4140 3783 3784 3785 3786 3787 3788 3789 3790 3791 3792 3793 1010 1011 1012 1013 1014 1015 1016 1017 1018 1019 1020 1021 1386 1387 1944 1945 1946 1947 1948 1949 1950 1951 1952 2205 2206 2207 2513 2514 2515 2516 2517 2518 2519 2520 2521 3206 3207 3208 3446 3447 3448 3449 3450 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3620 3621 3622 3623 3624 3625 3626 3627 1055 1056 1057 1058 1059 1060 1061 1062 1063 1064 1065 1066 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 3016 3017 3018 3019 3020 3021 3022 3023 3024 3025 3026 3027 2193 2194 2195 2196 2197 2198 2199 2200 2201 2202 2203 2204 2419 2420 2421 2422 2423 2743 2744 2745 2424 2425 2426 2427 659 660 661 651 654 655 656 657 658 941 942 943 1310 1311 1312 1313 1314 1315 1316 1317 1318 1399 1400 1401 1512 1513 1514 1515 1516 1517 1518 1519 1520 2096 2097 2098 2706 2707 2708 2709 2710 2711 2757 2713 2714 3275 3276 3277 3806 3807 3808 3809 3810 3811 3812 3813 3814 3815 3816 3817 2192 2191 2190 2189 2188 2187 2186 2141 2142 2143 2144 2145 2682 2683 2684 2685 2686 2687 2688 2689 2690 2691 2692 2693 3640 3641 3642 3643 3644 3645 3646 3647 3649 3650 3651 572 573 574 575 576 577 578 579 580 910 947 948 1471 1472 1473 1474 1475 1476 1477 1478 1479 1470 1480 1481 1962 1963 1964 1965 1966 1967 1968 1969 1970 2125 2126 2127 2549 2550 2551 2552 2553 2554 2555 2556 2557 3218 3219 3220 3470 3471 3472 3473 3474 3475 3476 3477 3478 3479 3480 3481 972 982 983 973 974 975 976 977 978 979 980 981 1292 1293 1294 1295 1296 1297 1298 1299 1300 1409 1410 1411 1654 1655 1656 1657 1658 1659 1660 1661 1662 2146 2147 2148 2694 2695 2696 2697 2698 2699 2700 2701 2702 2703 2704 2705 3974 3975 3976 3977 3978 3979 2020 2021 2022 2023 2024 2025 2026 2027 2028 2208 2209 2210 3130 3131 3132 3133 3134 3135 3136 3137 3138 3224 3225 3226 3239 3240 3241 3242 3243 3244 3245 3246 3247 3248 3249 3250 1868 1869 1870 1871 1872 1873 1874 1875 1876 2090 2091 2092 3082 2885 2886 2887 2888 2889 2890 2891 2892 3310 3311 3312 4384 4385 4386 4387 4167 4168 4169 4170 4171 4172 4173 4174 1184 1185 1186 1187 1188 1189 1190 1191 1192 1460 1461 1462 1879 1880 1881 1882 1883 1884 1885 1886 1887 2093 2094 2095 3083 2893 2894 2895 2896 2897 2898 2899 2900 3313 3314 3315 4187 4188 4189 4190 4191 4192 4193 4194 4195 4196 4197 4198 1821 1822 1823 1824 3040 3041 3042 3043 3044 3045 3046 3047 3048 3049 3050 3051 4227 4228 4229 4230 4239 4240 4241 4242 4243 4244 4245 4246 826 827 828 829 830 831 832 833 834 835 836 837 1229 1230 1231 1232 1233 1234 1235 1236 1237 1442 1443 1444 1888 1889 1890 1891 1892 1893 1894 1895 1896 1897 1898 2235 2901 2902 2903 2904 2905 2906 2907 2908 2909 3319 3320 3321 3950 3951 3952 3953 3954 3955 3956 3957 3958 3959 3960 3961 1330 1331 1332 1333 1334 1335 1336 1337 1338 1339 1340 1341 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 2566 2567 3255 2568 2569 2570 2571 2572 2573 3256 3257 3258 3491 3492 3493 3494 3495 3496 3497 3498 3499 2305 2306 2307 2308 2309 2310 2311 2312 2313 3262 3263 3264 2993 2994 2995 2996 2997 2998 2999 3000 3001 3268 3269 3270 2287 2288 2289 2290 2291 2292 2293 2294 2295 3504 3505 3506 3507 3368 3369 3370 3371 3372 3373 3374 3375 3376 3377 3378 3379 3664 3665 3666 3667 3668 3669 3670 3671 3672 4418 4419 4420 1414 1415 1416 1672 1673 1674 1675 1676 1677 1678 1679 1680 2005 2006 2007 2248 2249 2250 2251 2252 2253 2254 2255 2256 2257 2258 2259 3688 3689 3690 3691 3692 3693 3694 3695 3696 3697 3698 3699 3052 3053 3054 3055 3056 3057 3365 3058 3059 3060 3366 3367 3830 3831 3832 3833 3834 3835 3836 3837 3838 3839 3840 3841 2947 2948 2949 3329 3330 2910 2911 2912 2913 2914 2915 2916 2917 2918 3194 3195 3196 project__name Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Gulkana Central Wood Heating Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro Based Electric Boilers Wrangell Hydro 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Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Chignik Lagoon Hydroelectric Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project Rehabilitation Humpback Creek Hydroelectric Project 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Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project North Prince of Wales Island Intertie Project Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Cordova Wood Processing Plant Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Allison Lake Hydro Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Haines (Chilkoot) Central Wood Heating System Construction Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro 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Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Nome Banner Peak Wind Farm Transmission Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Tok Wood Heating Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm Unalakleet Wind Farm 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McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery McGrath Heat Recovery Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Lake and Peninsula Borough Wood Boilers Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity Anchorage Landfill Gas Electricity 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Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Mekoryuk Wind Farm Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Kotzebue High Penetration Wind-Battery-Diesel Hybrid Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Delta Area Wind Turbines Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project Pillar Mountain Wind Project 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Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Sand Point Wind Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Saint Paul Fuel Economy Upgrade Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Alaska Sealife Center Ph II Seawater Heat Pump Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project Gartina Falls Hydroelectric Project City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation City-Tribe Biomass Energy Conservation Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Wood Heating in Interior Alaska Communities Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Kaltag Solar Construction Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Hoonah Heat Recovery Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Pelican Hydroelectric Upgrade Project Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Sleetmute Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Savoonga Heat Recovery - Power Plant to Water Plant Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Chevak Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Surplus Wind Energy Recovery for Gambell Water System Heat Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Mentasta Woody Biomass Community Facility Space Heating Project Waterfall Creek Hydroelectric Project Waterfall Creek Hydroelectric Project Waterfall Creek Hydroelectric Project Waterfall Creek Hydroelectric Project Waterfall Creek Hydroelectric Project Waterfall Creek Hydroelectric Project Waterfall Creek Hydroelectric Project Waterfall Creek Hydroelectric Project Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Banner Peak Wind Farm Expansion Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Point Lay Heat Recovery Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Atmautluak Washeteria Heat Recovery Project Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant and Washeteria of Quinhagak Heat Recovery for the Water Treatment Plant & Community Store for Marshall Heat Recovery for the Water Treatment Plant & Community Store for Marshall Heat Recovery for the Water Treatment Plant & Community Store for Marshall Heat Recovery for the Water Treatment Plant & Community Store for Marshall Heat Recovery for the Water Treatment Plant & Community Store for Marshall Heat Recovery for the Water Treatment Plant & Community Store for Marshall Heat Recovery for the Water Treatment Plant & Community Store for Marshall Heat Recovery for the Water Treatment Plant & Community Store for Marshall Heat Recovery for the Water Treatment Plant & Community Store for Marshall New Stuyahok Heat Recovery New Stuyahok Heat Recovery New Stuyahok Heat Recovery New Stuyahok Heat Recovery Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Tazimina Hydroelectric Project Capacity Increase Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Eagle Solar Array Project Ketchikan Gateway Borough Biomass Heating Project Ketchikan Gateway Borough Biomass Heating Project Ketchikan Gateway Borough Biomass Heating Project Ketchikan Gateway Borough Biomass Heating Project Ketchikan Gateway Borough Biomass Heating Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project Seldovia House Ground Source Heat Pump Project actual_ff_om_hours 0 actual_ff_om_price 0 actual_ff_price 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.91 4.09 4.35 4.35 4.35 4.35 4.35 4.2 3.62 3.62 4.16 4.16 4.28 4.28 4.28 4.28 4.28 4.28 4.28 3.87 3.87 3.93 4.03 4.21 4.07 3.82 3.52 3.87 3.87 3.87 3.87 3.87 3.87 3.87 3.87 2.09 2.09 2.09 2.09 3.49 3.49 3.49 3.49 3.49 3.49 3.49 3.49 3.49 3.49 3.49 4.09 4.09 4.09 4.09 4.09 4.09 4.09 4.09 4.09 4.09 4.09 4.09 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 4.1 4.1 4.1 4.1 4.1 5.23 4.3 4.3 4.3 4.18 4.18 4.18 4.18 4.18 4.18 4.1 4.1 4.1 3.91 3.91 3.91 3.91 3.91 3.91 3.83 3.83 3.83 3.83 4.51 4.51 4.51 4.51 4.51 4.51 4.51 4.51 4.51 4.51 3.57 3.57 3.57 3.57 3.57 3.57 3.56 3.64 3.97 4.11 4.14 4.14 4.14 3.62 3.86 3.94 3.83 3.74 3.64 3.58 3.54 3.67 3.63 3.63 3.52 3.56 3.53 3.61 3.49 3.46 3.59 3.57 3.53 3.54 3.54 3.55 3.56 3.46 3.46 3.46 3.46 3.46 4.62 4.62 4.62 4.62 4.62 4.62 4.62 4.62 4.62 4.62 4.62 4.62 4.49 4.49 4.16 3.64 3.64 3.22 3.58 3.9 3.9 3.9 3.58 3.58 3.58 3.58 3.62 3.62 3.61 3.62 3.62 3.62 3.62 3.62 3.58 3.61 3.61 3.62 3.62 3.62 3.62 3.62 3.62 3.62 3.61 3.61 3.59 3.59 3.61 3.62 2.96 2.96 2.98 2.96 2.66 2.66 2.69 2.69 2.4 2.38 2.38 4.67 4.67 4.67 4.67 4.61 4.85 4.74 4.85 4.23 4.2 4.22 4.22 4.34 4.34 4.48 4.36 4.36 4.09 4.09 4.39 0 4.39 4.39 4.21 4.21 4.21 4.21 4.29 4.29 4.39 4.29 4.36 4.36 4.36 4.36 4.35 4.35 4.35 4.35 4.5 4.35 4.39 4.12 4.05 4.36 3.98 4.36 4.35 3.98 4.35 3.84 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 2.6 2.6 2.6 2.6 2.6 2.6 2.6 3.11 3.11 3.11 3.11 3.11 3.11 3.11 3.11 3.11 3.17 3.17 3.17 3.09 3.21 3.21 3.21 3.21 3.21 3.21 3.21 3.21 3.21 3.21 3.21 3.21 3.21 3.21 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 4.45 4.45 4.45 4.45 4.45 4.45 4.45 4.45 3.65 3.65 3.65 3.49 3.49 3.65 3.65 3.65 3.65 3.49 3.49 3.49 3.75 3.75 3.75 3.75 3.75 3.75 3.63 3.63 3.63 3.63 3.63 3.63 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.78 3.78 3.78 3.79 3.79 3.79 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.77 3.77 2.66 2.66 2.66 2.66 2.66 2.66 2.66 2.66 2.66 2.66 2.4 2.4 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.92 2.64 2.64 5.4 5.4 5.4 5.41 5.41 5.4 5.41 5.4 5.4 5.49 5.49 5.49 5.49 5.49 5.49 5.49 5.49 5.49 5.49 5.49 5.49 5.49 5.49 5.49 2.91 2.91 2.91 2.91 2.91 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 7.43 7.43 7.43 7.43 7.43 7.43 7.43 7.19 7.19 7.46 7.46 7.46 7.46 7.46 7.46 7.46 7.46 7.46 7.46 7.56 7.67 7.67 7.67 7.67 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 5.86 4.49 4.49 4.49 4.49 4.19 4.32 4.32 4.32 4.32 3.97 3.98 4.75 4.85 4.85 4.85 4.98 4.98 4.98 5.14 5.14 5.29 5.29 5.29 5.4 5.4 5.4 5.42 5.42 5.42 5.37 5.37 5.37 4.84 4.84 4.84 4.39 4.39 4.39 4.22 4.22 4.22 4.27 4.27 4.27 4.72 4.72 5.09 3.28 3.28 3.28 3.28 3.28 3.28 4.09 4.09 4.09 4.09 4.09 4.46 4.46 4.46 4.46 4.46 4.46 4.46 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 3.45 3.45 3.45 3.22 3.22 3.22 3.22 3.22 3.22 3.22 3.22 3.22 3.22 3.22 3.22 3.22 3.22 3.22 4.54 4.54 4.54 4.54 4.54 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.98 3.97 4.23 4.23 4.23 4.23 4.23 4.23 4.23 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.82 3.82 3.82 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.83 3.96 3.96 3.96 3.96 3.96 3.96 3.96 3.54 3.54 3.54 3.54 3.54 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.57 3.41 3.41 3.41 3.41 3.41 3.41 3.86 3.86 3.86 3.86 3.86 4.12 4.12 4.12 4.12 4.12 4.12 4.12 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.82 3.82 3.82 3.76 3.76 3.76 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 4.02 4.02 4.02 4.02 4.02 4.02 4.02 4.02 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.51 3.85 3.85 3.85 4.01 3.55 3.52 3.52 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.55 3.63 3.42 3.42 3.46 3.46 3.46 3.46 3.46 3.46 3.52 2.76 2.76 2.76 2.76 2.76 2.79 2.79 2.79 2.79 2.79 2.79 2.85 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.35 2.71 2.78 2.7 2.59 2.6 2.58 2.75 2.75 2.66 2.54 2.41 2.58 2.53 2.59 2.68 2.66 2.65 2.98 2.79 2.91 2.47 2.71 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.74 2.98 3.33 3.51 3.54 3.27 3.33 3.3 3.19 3.47 3.49 3.47 3.34 3.62 3.87 3.73 3.74 3.79 3.83 3.75 3.76 3.64 3.63 3.6 3.53 3.49 3.47 3.47 3.5 3.39 3.4 3.34 3.4 3.35 3.37 3.38 3.45 3.41 3.54 0 3.53 3.55 3.55 3.55 3.65 3.06 3.06 3.06 2.38 2.52 2.61 2.07 1.63 1.56 1.7 2.07 2.26 2.14 2.03 2.07 2.22 2.46 2.46 2.46 2.46 1.98 1.98 1.98 1.98 1.98 1.98 1.98 1.98 1.98 2.76 2.76 2.76 2.76 2.76 2.76 2.76 2.76 4.08 4.08 4.08 4.08 4.08 4.08 4.08 4.08 4.08 4.44 4.44 4.44 4.25 4.25 4.25 4.25 4.25 4.25 4.25 4.25 4.25 4.25 4.25 4.14 4.14 4.14 4.06 4.06 3.71 3.71 3.71 3.71 3.71 3.01 3.01 3.01 3.07 3.07 3.07 3.07 3.05 3.05 3.05 3.05 3.06 3.06 2.85 2.89 2.89 2.89 2.89 2.89 2.89 2.89 2.89 2.89 2.89 2.89 2.89 2.9 2.9 2.9 2.9 2.9 4.42 4.42 4.42 4.42 4.42 4.42 4.42 4.22 4.22 4.22 4.22 4.22 7.99 7.99 7.99 7.99 7.99 7.99 7.99 7.99 7.99 7.99 2.14 2.14 2.14 2.71 2.78 2.7 2.59 2.6 2.58 2.75 2.75 2.66 2.54 2.41 2.58 2.53 2.59 2.68 2.66 2.65 2.98 2.79 2.91 2.47 2.71 2.42 1.65 1.42 1.5 1.45 1.6 1.61 1.98 1.52 1.44 2.47 1.31 1.6 0.97 1.05 1.12 1.32 1.57 1.37 1.4 1.4 1.32 1.65 1.36 1.6 4.53 4.53 4.53 3.02 4.53 4.53 4.53 4.53 4.53 4.53 4.53 4.53 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.46 4.53 4.53 4.53 4.53 4.53 4.53 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.68 3.78 3.78 3.78 3.78 3.78 3.78 3.78 3.78 3.78 3.78 3.78 3.78 2.84 2.84 2.84 2.98 2.98 2.98 2.98 3.02 3.02 3.02 3.02 3.02 3.03 3.03 3.03 3.03 3.03 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 3.67 3.67 3.67 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.21 4.21 4.21 4.21 4.21 4.21 4.21 4.21 4.21 4.21 4.21 4.21 2.88 2.88 2.88 2.88 2.88 2.88 2.77 2.77 2.77 2.77 2.77 2.77 3.6 3.96 3.97 3.99 3.89 3.94 3.94 3.94 3.69 0 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 2.3 3.99 3.99 3.99 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4 4 4 4 4 4 4 3.37 3.37 3.37 1.53 1.38 1.47 1.56 1.76 2.09 2 1.78 1.91 1.9 4.65 4.53 4.53 4.53 4.53 4.53 4.53 4.53 4.53 4.53 4.53 4.53 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.91 3.72 3.72 3.72 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.86 3.89 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 3.91 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.41 2.75 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 3.96 3.96 3.96 4.07 4.07 4.07 4.07 4.07 4.07 4.07 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.9 3.9 3.9 3.9 3.93 3.93 3.93 3.93 3.93 3.93 3.93 3.93 3.93 3.93 3.93 4 4 4 4 4 4 4 4 4 4 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.28 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.99 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 4.11 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 3.14 3.14 3.14 3.14 3.14 3.14 3.14 3.14 3.14 3.14 3.14 3.14 3.14 3.14 3.14 11 11 11 11 11 11 11 11 11 11 11 11 11 4.51 4.48 4.61 4.72 4.81 4.81 4.62 4.15 4.55 4.55 4.55 4.59 4.55 4.57 4.4 4.66 4.66 4.66 4.66 4.66 4.73 4.73 4.69 4.71 4.54 4.54 4.54 4.54 4.57 4.57 4.57 4.57 4.57 4.6 4.6 4.67 4.54 4.54 4.54 4.54 4.57 4.57 4.57 4.57 4.57 4.57 4.57 4.57 4.54 4.54 4.54 4.54 4.57 4.57 4.57 4.57 4.57 4.57 4.57 4.57 5.18 5.18 5.18 5.18 5.18 5.18 5.18 5.18 5.18 5.18 5.18 5.18 3.36 3.36 3.36 3.36 3.36 3.46 3.36 3.36 3.36 3.36 3.36 3.36 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.82 3.82 4 4 4 4 4 4 4 4 4 4 4 4 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.46 2.46 2.46 2.46 2.46 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5 5 5 5 5 5 5 5 5 5 5 5 5 5 4.11 3.65 3.65 3.65 3.65 3.65 3.65 3.65 3.65 3.65 3.76 3.76 3.76 3.76 3.76 3.76 3.76 3.76 3.76 3.76 3.76 3.76 3.76 3.01 3.01 3.01 3.01 3.01 3.01 3.01 3.01 3.01 3.01 3.01 3.01 4.23 4.22 4.22 4.2 4.2 4.2 4.07 4.07 4.07 3.91 3.91 3.91 2.5 2.33 2.34 2.38 2.29 2.58 2.38 2.32 2.65 2.52 2.71 2.74 4.47 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.54 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 4.47 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 6.33 6.33 6.33 6.33 6.33 6.33 6.33 6.33 6.33 3.19 3.19 3.19 5.2 5.2 5.1 5.1 5.1 5.1 5.1 5.1 4 4 4 4 4 4 4 4 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 4.05 3.61 3.61 3.61 3.61 3.61 3.61 4.65 4.65 4.65 4.65 4.65 4.65 4.28 4.28 4.28 4.28 4.28 4.28 4.43 4.43 4.43 4.43 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 3.21 3.21 3.21 3.21 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.39 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 4.87 4.87 4.87 4.87 4.87 4.87 4.87 4.87 4.87 4.87 4.87 4.87 6.73 6.73 6.73 6.73 6.73 6.73 6.73 6.73 6.73 6.73 6.73 6.73 2.7 2.7 2.7 2.7 4.67 4.67 4.67 4.67 4.67 4.67 4.67 4.67 4.67 4.67 4.78 3.2 3.2 3.2 3.21 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 actual_ff_quantity 152 30 2523 9913 6330 7095 3172 4056 4587 5276 6818 7403 8064 7275 8159 7716 6637 6304 3416 4468 4087 5228 5468 8851 9251 3604 56 2852 856 0 0 0 145 1 341 290 45 7084 125 437 483 0 0 15 177 0 0 0 1412 1616 52 741 377 45 14 44 273 32 0 0 2646 48 237 1387 757 0 0 0 0 0 577 179 0 1025 1183 2784 1355 14 45 18590 18979 14066 14456 75965 76674 132212 97599 136167 102240 18401 2458 6894 9986 24487 39057 107283 134334 84388 74353 133499 154754 31686 3648 15408 38510 14468 5163 37618 97690 38454 72415 103401 110476 8584 9265 49924 30093 15227 623 662 1182 251 1702 36 67 0 148 207 68 179 335 17 0 0 20 64 41 546 497 123 0 0 0 102 0 20 0 0 288 1439 2590 0 0 0 0 0 0 0 0 0 0 0 287 486 369 0 623 358 374 0 0 0 0 0 0 0 0 0 0 0 0 0 95 101 0 290 0 0 111 0 219 189554 179713 184904 184478 181442 144940 170509 153524 188818 134691 172760 180118 159105 168477 180862 163035 154713 156662 151504 187413 141404 164131 142780 178788 3993 19345 16016 18541 20584 20522 18079 21165 20974 19687 18724 19520 18530 17207 18736 21315 18443 20669 19457 21376 21986 17498 20303 23138 20476 20770 17314 19510 19697 22081 20578 17054 18230 18618 9887 10098 23572 13959 10978 20380 20368 12485 18145 4126 4629 1247 1706 269 0 0 79 0 75 1177 0 420 2370 1080 519 1641 2687 2943 2998 1643 255 255 3198 4494 2110 2171 824 439 199 464 1320 648 404 1651 34398 30181 36266 38154 37051 30007 34426 38530 39426 47363 46454 33081 46841 45219 47012 43283 45754 40671 42913 43515 43477 48951 93941 89394 9638 10885 10693 9036 9191 7819 7417 8237 7525 8092 11217 13578 10854 11350 13136 9592 7508 7228 8838 10439 8414 12361 12377 12828 14106 10713 12330 10695 8955 7680 8828 7875 8153 9115 10120 12630 11207 10267 9620 8794 7684 6832 6556 9232 9230 8383 12225 14169 15214 13428 12429 11618 8405 7450 7553 8282 10850 9774 10886 12499 18980 18049 17684 15583 16750 13000 13375 14507 14532 17058 17911 20462 16862 17053 18148 15626 15154 12656 14198 15085 13743 16753 18412 19101 17299 17771 20127 18920 20951 18424 18169 14838 14616 13485 15727 14691 17800 21999 19530 21186 18483 19615 18034 15624 12562 12976 13995 14496 18038 17879 18979 5791 5374 6380 5216 5355 4378 4267 4104 4112 4903 4807 4982 6078 5520 6710 5696 5095 3864 3992 4590 5032 4309 4510 5135 4948 5659 4669 4359 3920 3652 3663 3735 4461 84543 6112 6225 5528 4368 5105 4577 4033 4142 4385 4646 4174 6646 6833 6585 6139 5954 5406 4536 3771 3739 4407 4334 4576 5128 5230 97347 109504 109389 87945 115471 117370 136812 118598 85367 91354 108574 78123 91183 94254 94133 94977 122941 101801 117126 103366 96677 90437 99187 83273 99402 108512 110064 91643 107806 99685 116932 101314 92199 85774 93943 85391 100699 120533 118712 109384 81871 110777 91417 91417 97037 94942 107331 106526 2325791 1923725 1912512 2254182 2086056 1696674 1532496 1610700 1722882 1828554 2075640 2311050 2221842 2008566 1978872 1850856 1628886 1408932 2074086 1942668 1941534 2423630 43027 70504 70021 15742 17763 9580 131877 55732 46655 29629 4336 1934 9425 2594 5344 0 3188 0 2105 1802 320 421 2439 973 4760 3504 1570 497 6169 922 403 74 1691 1077 1325 1597 2423 2253 1409 729 15585 533 2117 969 6324 3475 22 2372 3311 4779 963 56548 70747 5621 6224 5988 5877 5819 7025 7134 7187 6937 6744 8238 7162 6350 5148 8339 6616 7138 7673 7877 5758 7254 5932 5531 6251 6251 7166 5352 5815 5352 5650 7191 7171 5435 6665 6728 5938 4040 5034 8491 7281 6907 7336 3238 6350 7860 9242 8868 2325791 1923725 1912512 2254182 2086056 1696674 1532496 1610700 1722882 1828554 2075640 2311050 2221842 2008566 1978872 1850856 1628886 1408932 2074086 1942668 1941534 2423630 2023308 2143008 2597280 2287614 2251242 2480268 1895628 1753794 2007264 2409068 2409068 2651838 2093438 6030 5648 5493 5848 5563 6158 4629 5357 6482 5648 6135 6903 7064 6135 5521 6498 6244 5722 5413 5567 6754 5884 5599 5793 5637 6064 4643 6093 6048 5727 5519 6395 6413 6096 6344 6196 6444 5524 5652 5308 6030 5866 5843 7333 5096 5212 5874 5757 6532 6420 4122 6312 6402 5607 5533 6608 5894 6736 6810 7239 0 0 0 0 0 0 0 0 0 857 35 6605 6880 6426 8008 6627 5860 7026 6696 7594 6439 6898 8566 5917 6833 6688 9096 6921 5629 7977 6679 5934 7612 6647 8028 5233 6089 7062 6351 5858 5361 6842 6748 6392 7538 6951 6270 8378 6486 6024 9200 6720 6010 7998 7378 6951 8357 6869 8117 19214 20214 18907 19195 18460 20768 25970 26006 21053 18822 22555 21382 20239 22236 22856 20131 22136 23692 28842 26258 22440 22516 21006 20858 23787 24488 24991 19566 22150 26869 28579 29528 22217 19615 17884 17934 16275 18069 14442 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194063 173165 192389 57315 67888 50994 90637 98397 69336 54998 90601 222249 375644 232075 220543 61466 117153 60517 170305 120443 142860 128174 153877 184219 271474 342629 259130 323146 328910 334103 290990 267689 214060 223413 271890 276207 290643 320090 398429 365189 339177 331818 289989 255746 231304 213593 248180 303240 312150 332810 377640 272000 2674000 5809000 5380000 4724000 3111000 4534000 4228000 4260000 5173000 5355000 5253000 5396000 5794000 6864000 6303000 4190000 5294000 3906000 6573000 4824000 4369000 6499000 3291000 6062000 8736000 9712000 6307000 3157000 6463000 4840000 4347000 5052000 4691000 3806000 4009000 5390000 6638000 5510000 78 948 2409 2979 3093 3284 3328 1464 3169 2410 729 60 actual_net_electricity_to_secondary_loads 0 16016 17954 11034 4360 2965 2489 2139 5588 5947 6345 7778 14894 13640 7074 6716 8529 2545 4372 5868 7883 16043 0 0 0 0 0 0 0 0 0 93 78 119 97 225 290 326 3600 80 1030 1788 2102 2094 2164 1469 1817 3176 1435 209 994 418 62 0 0 0 0 0 3695 3396 3512 3051 967 675 916 2609 35944 21809 1187 488 645 130 72 77 4371 3083 6736 5495 11 207 0 1 2329 792 1455 19 1049 2963 2617 1078 1890 1862 1517 130 501 261 312 581 1146 1489 744 729 3365 405 190 947 382 0 1444 456 1810 605 851 1801 2018 1746 824 449 884 198 213 1260 1078 4798 4542 2457 1353 1584 1261 1365 171 596 640 536 1329 0 7262 5619 3935 3471 3841 1623 737 1171 113 866 5076 2360 3160 10378 2918 3342 1194 303 175 1040 1823 1892 509 2953 5146 1252 27 228 349 241 1415 800 1336 46 840 2346 1130 133 64 34 102 1165 223 556 520 1486 2128 418 2998 3973 2467 8982 22000 22387 21922 24841 18062 19361 22815 16754 16236 20667 19586 22042 4559 1354 9729 6440 12709 6111 1648 3887 9851 10628 345 21 394 434 11 0 3877 3987 9572 740 17618 6997 9371 11594 6477 2864 8457 9243 1687 8003 7647 3724 5741 2162 2309 3074 6052 6091 5722 9392 9533 36389 15845 14812 21766 18923 10784 6725 9265 17568 15164 12865 13065 22391 20908 11928 13853 12920 5083 2454 3799 13473 20708 23501 18905 24973 32256 15262 20625 13403 5912 1227 2666 6481 11482 15497 13551 18052 9533 8701 4381 4534 1934 6557 17549 19604 16223 8420 14335 18044 5895 2894 1 11 318 6632 9524 2572 13416 8557 10706 6267 5900 9143 6508 3938 9667 8589 4413 9260 13232 7708 9712 0 3507 4724 3140 2469 5538 9810 5430 8454 10929 7966 16487 6454 6667 4411 4743 3928 7099 15670 9600 13183 822 542 873 31 171 141 237 169 121 229 59 1979 2544 1301 140 537 112 316 597 549 656 718 730 775 642 703 731 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5685 6467 5462 3339 1228 911 7492 2825 5072 7878 7723 8676 8880 12284 4366 4508 4201 3588 4252 431 3945 2321 13984 13947 14551 798 2573 1052 460 1315 2630 1610 372 1778 2210 11278 4711 9273 18966 15092 20387 912 1005 8822 6653 5313 3151 3343 5044 4521 4377 6588 7555 5446 7685 7007 4449 1768 2794 70 38 8139 10067 14326 896 19166 26137 19805 11527 8762 4060 1207 3948 3723 27795 21347 22883 15846 5867 18900 23721 22296 16603 14719 10759 4511 3309 6224 9011 9368 8654 2134 1160 471 1246 4531 9060 5454 4585 4538 102 277 0 899 1600 2360 2511 1687 3053 3450 7810 5093 4003 2976 2010 3918 1738 870 262 588 468 557 467 354 723 233 532 474 271 170 39 165 1911 3505 368 271 86 729 787 670 589 80 193 783 232 2297 1095 1161 1697 1830 341 893 1152 174 531 163 464 13601 21912 14126 250 200 159 148 144 237 141 157 298 18422 14285 3322 1233 1113 739 565 400 493 864 653 503 403 452 850 871 1783 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 actual_net_heat_output 120 120 120 200 200 200 200 100 600 80 0 140 120 140 120 100 0 0 0 0 140 140 140 120 140 160 60 0 0 0 0 20 100 160 160 38.7 38.7 30.1 12.9 0 0 0 0 0 17.2 34.4 25.8 95 95 81 27 0 0 0 0 81 81 68 81 68 40.8 54.4 0 0 0 0 0 0 253.114 994.462 635.055 711.811 318.176 406.861 460.149 529.256 683.935 742.67 808.937 729.83 818.52 774.05 665.78 632.46 342.68 448.22 409.97 524.46 548.57 887.88 928.08 909 948.81 742.59 803.46 641.32 155.18 323.73 298.07 438.65 557.79 692.23 818.33 860 1155.8 926.2 849.9 465 453.7 334 322 461.4 531.3 924.79 877.57 850.68 827.615 718.431 578.13 624.123 507.16 336.287 381.393 509.48 587.273 784.351 883.162 483 425 385 297 348 183 77 113 74 22 36 51 500 500 500 40 200 360 0 0 0 0 0 0 0 0 0 720 0 0 0 0 0 0 0 0 0 300 240 0 0 0 0 0 0 0 40 39 40 48 45 31.173 32.328 30.019 24.246 23.091 20.205 20.782 23.669 25.689 0 0 0 34.925 31.462 34.925 33.771 19.628 19.05 19.628 19.628 19.05 34.925 23.957 25.69 22.225 17.03 15.298 12.123 10.102 15.009 0 0 0 0 0 0 0 0 0 0 0 0 360 309 604 1145 864 720 720 1151 425 415 835 776 326 0 0 0 0 98 583 492 1376 1053 538 430 215 172 516 688 1118 903 1238.4 950.3 774 215 0 0 0 0 645 688 722 1224 1020 870 680 215 0 0 0 0 803 824 1535 4015.15 3815.15 1338.38 803 824 1535 51.914 58.196 35.766 14.133 9.611 8.068 6.933 18.113 19.277 20.567 25.212 48.277 44.213 22.93 21.769 27.646 8.249 14.171 19.021 25.552 52.002 37 33.3 17.5 20.7 18.2 9.4 18.8 38.2 34.7 95 76 38 19 0 0 0 0 19 19 38 76 463 401 321 246 168 90 125 124 155 239 281 283 338 289 300 258 204 93 78 119 97 225 290 326 286 246 267 276 225 66 77 124 114 276 299 244 288 213 314 241 120 97 103 77 185 270 248 271 250.407 256.089 231.731 235.534 138.726 105.453 77.058 85.692 198.384 254.857 255.819 300.518 264 365 260 222 154 113 87 114 152 223 203 191 11.32 9.06 4.53 2.26 0 0 0 0 2.26 2.26 4.53 9.06 13.6 10.88 5.44 2.72 0 0 0 0 2.72 2.72 5.44 10.88 521 390 514 276 205 159 241 597 633 428 416 289 100 329 298 478 399 501 258 344 0 0 0 0 0 283 537 561 481 465 248 250 80 99 391 241 450 525.92 530.423 212.277 168.965 99.346 0 0 0 235.428 243.508 24.59 0 511.98 462.88 329.66 265.59 35.87 19.8 78.2 68.2 243.89 301.89 362.2 353.848 14.778 4.389 31.536 20.875 41.195 19.808 5.342 12.599 31.931 34.45 1.118 0.068 1.277 1.407 0.036 0 12.567 12.923 31.027 2.399 57.107 22.68 30.375 37.581 20.995 9.283 27.413 29.96 5.5 25.9 24.8 12.1 18.6 7 7.5 10 19.6 19.7 18.5 30.4 0 0 0 0 0 25 29 22 36 6 0 0 0 0 0 0 0 24.498 21.526 18.404 30.824 12.88 0 0 0 0 0 0 0 24.498 21.526 18.404 30.824 12.88 0 0 0 0 0 0 0 24.67 24.02 19.6 32.55 0 117.951 51.36 48.012 70.552 61.337 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68.25 68.25 68.25 68.25 68.25 68.25 68.25 68.25 68.25 68.25 68.25 68.25 68.25 65 65 65 65 65 65 65 65 65 65 65 65 actual_re_fuel_price_cords 20 250 250 250 250 250 250 250 250 250 250 250 200 200 200 200 200 200 200 200 250 250 250 250 250 250 250 250 250 250 250 250 200 200 200 200 200 200 200 200 200 0 0 0 0 0 0 0 0 0 0 250 0 0 250 250 54 350 350 350 350 350 350 350 350 350 350 350 350 69 69 69 69 69 69 200 200 200 200 200 200 4.05 200 200 200 200 200 200 200 200 200 200 200 200 200 200 200 200 300 300 300 300 300 300 300 300 300 300 300 300 85 85 85 85 85 85 85 85 85 85 85 85 300 300 300 300 300 300 300 300 300 actual_re_fuel_price_electricity 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.13 0.13 0.13 0.13 0.13 0.13 0.13 0.13 0.13 0.13 0.13 0.13 0 0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.15 actual_re_fuel_price_pellets 300 300 300 300 300 300 300 300 300 300 300 300 425 425 425 425 425 425 425 425 425 425 375 375 375 375 375 375 375 375 375 306 306 306 306 306 actual_re_fuel_quantity_chips 160 120 160 120 50 64 84 159 120 100 100 175 65 64 128 119 50 0 0 0 0 15 89 75 320 245 125 100 50 40 120 160 260 210 288 221 180 150 160 300 250 150 50 65 0 0 0 40 194 220 372 600 500 200 50 0 0 0 0 0 194 220 372 99 61 47 19 19 42 20 42 65 0 77 46 79 28 0 0 0 17 17 19 42 48 77 46 79 28 0 34 54 34 0 0 0 0 0 36 20 33 34 54 34 0 0 0 0 0 0 0 65 92 16 12 8 4 20 16 8 4 0 0 0 0 4 4 8 16 actual_re_fuel_quantity_cords 6 6 6 10 10 10 10 5 5 4 4 4 4 4 4 7 6 7 6 5 0 0 0 0 7 7 7 6 7 8 3 1 5 8 8 9 9 7 3 0 0 0 0 0 4 8 6 7 7 6 2 0 0 0 0 6 6 5 6 5 3 4 0 0 0 0 0 0 25 25 25 2 10 18 0 0 0 0 0 0 0 0 0 36 0 0 0 0 0 0 0 0 0 15 12 7 5 2 1 0 0 0 0 1 1 2 5 0 0 0 45 64 66 69 40 37 26 34 37 57 66 92 20 13 13 13 7 0 0 0 8 13 13 20 39 31 16 8 8 8 16 31 8 9 6 5 0 0 0 3 12 13 16 12 12 12 9 7 5 4 4 13 19 26 26 25 20 10 5 0 0 0 0 5 5 10 20 9 9 9 5 2 0 0 0 6 9 9 9 5 4 2 1 0 0 0 0 1 1 2 4 5 4 4 4 1 4 4 5 5 1 17 18 18 actual_re_fuel_quantity_electricity 78088 306800 195920 219600 98160 125520 141960 163280 211000 229120 249564 225160 252520 238800 205400 195120 138280 138280 126480 161800 169240 273920 286320 266440 278080 217640 235480 187960 45480 94880 87360 128560 163480 202880 239840 252040 338760 271440 249100 136280 132960 97880 94360 135240 155720 271040 257200 249320 242560 210560 169440 182920 148640 98560 111780 149320 172120 229880 258840 176531 69012 81262 64939 46417 58398 51247 41443 29009 25833 32372 33615 41006 51432 60696 49376 57458 50979 51733 32153 34250 30412 30588 31876 40446 50213 53098 49829 47926 45990 41132 34410 33729 36427 438662 39959 44891 48552 67135 56750 44230 44994 41571 34882 32788 31214 32590 34014 43406 41983 48750 42921 44756 27068 28583 25771 24970 26881 33630 42694 44499 70327 63522 63290 52423 33504 18311 11845 28314 37610 35125 72750 96501 68304 87092 74912 49299 31199 24697 20357 26295 24489 44791 45818 59450 77880 64731 66152 35705 27687 24060 19430 13298 29025 31490 48156 70882 59698 43132 45582 39813 26622 17065 9514 13301 15932 27661 40259 66737 70226 57335 56580 36890 28423 21059 14132 22370 31164 34767 51746 73393 0 21727 21063 25781 5012 5012 5012 5012 5012 5012 5012 5012 5012 actual_re_fuel_quantity_pellets 3 3 3 3 3 2.16 2.24 2.08 1.68 1.6 1.4 1.44 1.64 1.78 0 0 0 2.4 2.2 2.4 2.3 1.4 1.3 1.4 1.4 1.3 2.4 1.66 1.78 1.54 1.18 1.06 0.84 0.7 1.04 0 0 0 0 0 0 0 0 0 0 0 0 6 4 9 9 12 actual_re_om_hours 2 0 0 0 2 75 75 75 75 75 75 75 75 75 75 75 75 15 15 15 15 15 15 15 15 15 15 15 15 593 0 368 220 658 66 0 11 39 242 261 92 64 20 20 20 20 20 20 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 162 270 221 131 100 112 125 254 153 152 212 132 277 233 217 126 54 76 45 102 133 80 130 135 0 0 0 0 0 0 0 0 0 0 0 0 143 142 130 139 158 180 0 0 0 151 127 131 168 48 48 96 96 96 96 96 96 96 0 2 2 2 16 8 136 146 0 8 16 4 118 234 132 17 17 15 13 11 0 12 12 10 4 8 4 0 10 2000 4 8 4 6 4 107 129 129 94 271 102 81 76 105 91 124 471 458 540 394 379 373 263 225 324 360 446 432 531 407 566 452 853 435 359 419 356 3 5 18 4 3 3 5 1 0 0 0 0 0 0 0 0 720 312 0 0 0 0 0 0 0 0 0 0 42 53 38 59 103 56 41 42 51 18 37 28 58 54 71 50 35 11 26 38 44 36 47 46 336 336 368 0 0 0 0 0 0 0 0 0 0 0 0 204 161 164 281 93 87 90 208 101 94 95 106 66 0 11 39 242 261 92 64 2 8 2 3 3 350 350 200 0 0 720 696 744 144 actual_re_om_price 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 30 30 30 30 30 30 1641.63 681.11 25 25 25 25 25 25 25 25 25 25 0 0 0 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 0 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 22 22 22 22 22 22 22 22 22 22 25 25 25 25 25 25 25 50 50 1716 1716 250 250 25 25 0 0 0 0 0 0 actual_total_other_ff_om_costs 0 actual_total_other_re_om_costs 3500 6200 10470 6120 1350 1350 1350 1350 1350 1350 1350 1350 1350 1350 1350 1350 100 100 100 100 100 100 100 100 100 100 100 100 592 592 592 1078.43 0 0 0 0 0 0 0 0 0 0 0 0 1844 0 0 575 0 0 525 10575 3460 600 16.97 4394 0 3685 3872.94 9564.34 20244.44 18387.93 9255.53 26073.42 4228.44 4521.92 22998.95 23549.63 5572.8 30651.46 6018.97 5122.33 30118.69 6610.4 9513.64 23761.61 13513.41 14834.89 23903.15 24141.96 8705.4 95332.1 25 25 0 947 5300 506807 15298 17431 1966 23940 1034075 167423 8327 470 250 800 250 150 800 1400 250 800 250 0 0 0 0 0 0 0 320 250 1716 1716 850 0 1716 1716 2597.06 17227.4 9411.63 15767.48 8896.12 18135.19 1410.69 3333.89 8498.27 27318.46 14065.76 8217.18 21394.06 4947.18 11085.26 38092.58 6904.34 94480.93 13281.56 3094.25 1020.53 2922 1200 100 15 10 45 2225 35 20 5 5 15 95 180 25 200 200 3000 2262 2487.79 3626.5 2092.25 4025.06 10385.37 3376.76 2214.42 2762.13 2981.7 1481.56 3019.03 3426.37 3374.07 2440.87 4291.96 2557.09 1971.68 347.59 1622.71 2118.01 6804.99 2070.6 2621.96 2683.99 2006 2010 168 0 0 37277.46 552.14 2004.95 2177.19 473.59 557.44 211.55 547.38 7286.85 2416.74 1293 2269 3231 96546.41 140 558 140 279 0 50 0 0 0 0 0 0 0 alternate_total_actual_ff_om 0 alternate_total_actual_re_om 1709.76 1709.76 1709.76 1709.76 1709.96 1709.76 1709.76 1709.76 1120 1250 1075 1270 4230 1390 1140 5450 1450 2750 1800 1260 4200 3340 2290 4040 1480 2355 4360 4800 1550 1550 2200 2300 220 2350 3100 4320 3777 2460 1418.36 10740 1714 4192 5904 5788 44498 1350 1350 1350 1350 1350 1350 1350 53734 33386 19483 20234 11596 6111 10670 15722 14700 13422 13670 14840 19265 18065 19581 19470 13630 12023 11811 12139 8278 10494 14321 21237 12307 14593 14678 17457 19169 17618 24569 18935 18280 14900 28194 22935 20090 15992 24505 23378 16843 26381 16348 10496 20649 23479 24714 14491 23207 15491 22869 592 592 592 399.23 364.95 853.18 2000.95 1260 869.58 2082.5 64.94 12 12 12 8 8 8 8 8 8 8 3555.46 6382.08 2833.96 7027.86 8409 9042 22017 4838 6150 9299 23290 13052 32835 10032.76 7939.09 13567.71 500 100 45 6180.66 6180.66 6180.66 6180.66 6180.66 6180.66 5513.98 5513.98 5513.98 960 960 960 1000 2000 4000 7316 7316 7316 7316 7316 7316 7316 7316 7316 7316 7316 189831 200966 227261 228032 213379 308859 218452 213373 225118 274207 263129 240460 69571 124553 45303 144747 71099 149025 41090 89027 99039 43571 84408 155811 3799 8011 107474 102645 88563 72654 193495 89255 99807 3142 2400 17475 111 560 6478 1716 1716 1716 13163.31 14485 13324 33202.06 25765.06 13490.1 9881.31 8262.94 9957.42 9957.42 17994.5 50531 37467 76393 49665 62410 43157 40727 37287 68801 62940 54441 91708 6699 0 350 350 350 350 250 250 450 650 650 650 178.62 193016 73273 0 11738 9179 8417 6717 20466 22395 10260 13826 12700 0 alternate_total_cost_of_re_fuel 6247.04 24544 15673.6 17568 7852.8 10041.6 11356.8 13062.4 16880 229120 19965.12 18013 20202 19104 16432 15610 8458 11062 10118 12944 13539 21914 22906 21315.2 22246.4 17411.2 18838.4 15036.8 3638.4 7590.4 6988.8 10284.8 13078 16230 19187 20163.2 27100.8 21715.2 19928 10902.4 10636.8 7830.4 7548.8 10819.2 12457.6 21683.2 20576 19945.6 19404.8 16844.8 13555.2 14633.6 11891.2 7884.8 8942.4 11945.6 13769.6 18390.4 20707.2 0 0 0 0 0 0 0 0 0 7.43 149107 135513 154559 160069 146370 129630 143540 155064 157580 165295 163359 153675 200431 195314 200971 193983 201974 185533 196906 198478 197601 227626 231787 223117 197593 203109 191073 178016 195032 200378 195664 195801 201533 180723 198800 199877 166549 150729 161104 156214 159051 143944 142756 145035 71620 160849 74926 149785 6494 4642 5840 5125 4144 2901 2583 3237 3361 4101 5143 6070 5431.36 6320.38 5607.69 5690.63 3536.83 3767.5 3345.32 3364.68 3506.36 4449.06 5523.43 5840.78 5481.19 5271.86 4524.52 3785.1 3710.24 4006.97 48252.82 4395.49 4938.01 5340.72 7384.85 6242.5 4865.3 4949.34 4572.81 3837.02 3606.68 3433.54 3584.9 3741.54 4774.66 4618.13 5362.5 4721.31 4923.16 2977.48 3144.13 2834.81 2746.7 2956.91 3699.3 4696.34 4894.89 4712.4 2815.2 4834.8 1713.6 0 0 0 1091.4 1091.4 1219.8 2696.4 3081.6 7264.78 6561.82 6537.86 5415.3 3460.96 1891.53 1223.59 2924.84 3885.11 3628.41 7515.08 9968.55 7479.29 8240.32 5422.89 3431.89 2716.67 2239.27 2892.45 2693.79 4927.01 5039.98 6539.5 8566.8 7120.41 7276.72 3927.55 3045.57 2646.6 2137.3 1462.78 3192.75 3463.9 5297.16 7797.02 7163.76 5175.84 5469.84 4777.56 3194.64 2047.8 1141.68 1596.12 1911.84 3319.32 4831.08 9129.38 7453.55 7355.4 4795.7 3694.99 2737.67 1837.16 2908.1 4519.71 4519.71 6726.98 9541.09 0 751.8 751.8 751.8 751.8 751.8 751.8 751.8 751.8 751.8 biomass_moisture_content 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 12 12 12 12 12 12 12 12 12 12 12 12 20 20 20 20 20 20 20 30 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 25 25 25 25 25 25 25 25 25 25 25 25 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 0 8 8 10 10 0 12 12 14 12 12 8 8 10 10 30 5 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 20 15 15 15 15 15 15 15 15 15 15 15 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 4 4 4 4 4 comments $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict $250.00 per cord (price quote from Dave, resident of Tok AK, Garn Representative for State of Alaska) – sold Garn system to Gulkana and Tim, resident of Kenny Lake, O&M manager for Kenny Lake School Disrtict System not operated in May. System did not operate in June. System did not operate in July. System did not operate in August. Replaced gasket, fire bricks and glycol pump. Started up for the 1st time with new fire bricks and pad under bricks 1 1/2 in September to test it. Everything went well and we are testing the TARN boiler. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. In August we had to maintenance the boiler. We actually just replaced the circulating pumps. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. When the Boiler is not running through the summer months we usually do maitenance on it. Change out the bricks if its bad, clean chimney pipes, change water system, run glycol though the system and all other tests before we start the Boiler up for the winter. Reported production was 225,160 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 252,520 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 238,800 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 205,400 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 195,120 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 138,280 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 138,280 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 126,480 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 161,800 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 169,240 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 273,920 kWh. Estimated heat production assumes an RE efficiency of 95%. Reported production was 286,320 kWh. Estimated heat production assumes an RE efficiency of 95%. Facilities pay 8 c/kWh for their hydro sourced electricity. Heat production estimates assumes 95% efficiency. The project pays 8 c/kWh for the hydro-sourced electricity. Heat production estimates assumes 95% efficiency. The project pays 8 c/kWh for hydro-sourced electricity. Heat production estimates assumes 95% efficiency. The project pays 8 c/kWh for the hydro-sourced electricity. Heat production estimates assumes 95% efficiency. The project pays 8 c/kWh for the hydro-sourced electricity. Heat production estimates assume 95% efficiency. The project pays 8 c/kWh for hydro-sourced electricity. Heat production estimate assumes 95% efficiency. The project pays 8 c/kWh for the hydro-sourced electricity. Heat production estimate assumes 95% efficiency. The project pays 8 c/kWh for hydro-sourced electricity. Heat production estimate assumes 95% efficiency. The project pays 8 c/kWh for hydro-sourced electricity. Heat production estimate assumes 95% efficiency. The project pays 8 c/kWh for hydro-sourced electricity. Heat production estimate assumes 95% efficiency. The project pays 8 c/kWh for hydro-sourced electricity. Heat production estimate assumes 95% efficiency. The project pays 8 c/kWh for hydro-sourced electricity. Heat production estimate assumes 95% efficiency. Net Generation is an imputed value based on the assumption that station service is 1% of gross generation. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 6,210 kWh Diesel kWh = 20,914 (12% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 4,950 kWh Diesel kWh = 647 (0% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 3,070 kWh Diesel kWh = 9,040 (6% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 3,590 kWh Diesel kWh = 5,127 (3% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 3060 kWh Diesel kWh = 637 (0% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 1,540 kWh Diesel kWh = 169 (0% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 1,010 kWh Diesel kWh = 535 (0% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 490 kWh Diesel kWh = 3,509 (2% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 540 kWh Diesel kWh = 445 (0% of total gross generation) Scheduled maintenance hours due to annual inspection and maintenance by turbine manufacturer. Total Station Service = 620 kWh Diesel kWh = 0 (0% of total gross generation) Nonscheduled maintenance hours due to voltage regulator breaking. Total Station Service = 1310 kWh Diesel kWh = 0 (0% of total gross generation) Station Service updated from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Total Station Service = 1,360 kWh Diesel kWh = 36,246 (22% of total gross generation) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) (calc'd from plant log engine hrs) 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 3. "Actual RE O&M hours" is the average between the Humpback Hydro, Power Creek Hydro, and diesel units. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1. "Actual fossil fuel quantity" is a function of the reported diesel kWh generated and the reported average diesel efficiency. 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross 1/13/2014: estimated net electric generation as 99% of gross Changed station service from assumption (1%*Gross Gen) to actual data based on values reported on O&M form. Humpback - 12.1% of total gross generation Power Cree kWh=628,464 (32% of total gross generation) Diesel kWh=1,083,539 (55.7% of total gross generation) Total Station Service = 36,935 kWh (station service adjusted according to energy source distribution). Changed station service from based on assumption (1% * Gross Gen) to actual reported value (based on energy source distribution, below) Humpback - 10.3% of total gross generation Power Creek HY kWh = 635,396 (35.7% of total gross generation) Diesel kWh = 960,634 (54% of total gross generation) Total Station Service = 36912 Updated station service from assumption value (1%*Gross Generation) to actual reported value based on energy source distribution. Humpback - (2.9% of total gross generation) Power Creek HY kWh = 118,638 (6% of total gross generation) Diesel kWh = 1,792,891 (91.1% of total gross generation) Total Station Service = 69,032 kWh Updated station service from assumed value (1% * Gross Generation) to actual reported value (based on energy source distribution, below) Humpback - 2.8% of total gross generation Power Creek Hydro - 15,719 kWh (0.7% of total gross generation) Diesel = 2,101,564 kWh ( 96.5% of total gross generation) Total Station Service = 73592 kWh Updated station service from assumed value (1%*Gross Generation) to reported value (based on energy source distribution, below) Humpback - 23.2% of total gross generation Power Creek HY kWh = 1,303,738 ( 56.8% of total gross generation) Diesel kWh = 458,495 (20% of total gross generation) Total Station Service = 31,906 kWh Updated station service from assumed value (1% of gross generation) to reported value (based on energy source distribution, below) Humpback - 23.9% of total gross generation Power Creek HY kWh = 2,232,138 (74.4% of total gross generation) Diesel kWh = 51,033 (1.7% of total gross generation) Total Station Service = 24,229 kWh Updated station service from assumed value (1%*gross generation) to reported value (based on energy source distribution, below) Humpback - 11.5% of total gross generation Power Creek HY kWh = 3,340,058 (83.3% of total gross generation) Diesel kWh = 208,464 (5.2% of total gross generation) Total Station Service = 25,121 kWh Updated station service from assumed value (1% * gross generation) to reported value (based on energy source distribution, below) Humpback - 9.2% of total gross generation Power Creek HY kWh - 3,375,254 (78.5% of total gross generation) Diesel kWh - 526,050 (12.2% of total gross generation) Total Station Service - 24,563 kWh Updated station service from assumed value (1%*gross generation) to reported value (based on energy source distribution below) Humpback - 15% of total gross generation Power Creek = 1,621,737 kWh (75.8% of total gross generation) Diesel kWh = 198,066 kWh (9.3% of total gross generation) Total Station Service = 24,503 kWh Total Station Service = 32,733 kWh (entered value has been adjusted based on energy source distribution, below) Humpback - 21.4% of total gross generation Power Creek HY kWh = 1,196,459 (74.1% of total gross generation) Diesel kWh = 72,390 (4.5% of total gross generation) Total Station Service = 33,350 kWh (entered value has been adjusted based on energy source distribution, below) Humpback - 9.3% of total gross generation Power Creek HY kWh = 1,045,890 (60.6% of total gross generation) Diesel kWh = 519,123 (30.1% of total gross generation) Total Station Service = 44,871 kWh (entered value has been adjusted based on energy source distribution, below) Humpback - 4.6% of total gross generation Power Creek HY kWh = 415,906 (22.2% of total gross generation) Diesel kWh = 1,372,551 (73.2% of total gross generation) Station service imputed as a proportion of total generation for the month. Station service calculated as proportion of total generation due to lack of station service for just HBC. Station service calculated as proportion of total generation due to lack of station service for just HBC. Station service calculated as proportion of total generation due to lack of station service for just HBC. Station service calculated as proportion of total generation due to lack of station service for just HBC. Station service calculated as proportion of total generation due to lack of station service for just HBC. Fuel price from AEDG - AHFC/DCRA Aug 2014 for Cordova. Fuel price from AEDG - AHFC/DCRA Aug 2014 for Cordova. Fuel price from AEDG - AHFC/DCRA Aug 2014 for Cordova. Fuel price from AEDG - AHFC/DCRA Aug 2014 for Cordova. Fuel price from AEDG - AHFC/DCRA Aug 2014 for Cordova. Fuel price from AEDG - AHFC/DCRA Aug 2014 for Cordova. Fuel price from AEDG - AHFC/DCRA Aug 2014 for Cordova. Fuel price from AEDG - AHFC/DCRA Aug 2014 for Cordova. Price of wood is an assumption. Per Chamber of Commerce in Cordova there are no firewood sellers in Cordova (and since not in road system wood can be purchased from other towns). People gather their own wood. No firewood was processed during this period. No firewood was processed during this period. No firewood was processed during this period. No firewood was processed during this period. No firewood was processed during this period. No firewood was processed during this period. No firewood was processed during this period. Price of wood is an assumption. Per Chamber of Commerce in Cordova there are no firewood sellers in Cordova (and since not in road system wood can be purchased from other towns). This system is used only to cut wood for the elders. Price of wood is an assumption. Per Chamber of Commerce in Cordova there are no firewood sellers in Cordova (and since not in road system wood can be purchased from other towns). This system is used only to cut wood for the elders. Per grantee: "On October 4, during a cold snap, both burners were moved to oil at the rec of the mfr. In December redesigned parts came in but were not installed by 12-31-13. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. Production data is only for the system on building A. The system in building B did not operate due to issues that resulted in the system not operating consistently. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. The grantee is not currently operating the biomass system because it is cheaper to heat with heating fuel. Hatchery using little water Unit 2 runner replaced Low water in reservoir Net generation assumes 2.4% of parasitic load. Net generation assumes 2.4% of parasitic load. Net generation assumes 2.4% of parasitic load. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. An entry of 8500 kWh was reported for Actual RE Net Generation. It appears to be an error so it was removed. (Alex, 01/09/2014) Assumption: 50% of the BTU's produced are used to heat the school. The remaining BTU production is used for electrical generation and waste heat. Assumption: 50% of the BTU's produced are used to heat the school. The remaining BTU production is used for electrical generation and waste heat. Assumption: 50% of the BTU's produced are used to heat the school. The remaining BTU production is used for electrical generation and waste heat. Assumption: 50% of the BTU's produced are used to heat the school. The remaining BTU production is used for electrical generation and waste heat. Assumption: 50% of the BTU's produced are used to heat the school. The remaining BTU production is used for electrical generation and waste heat. School closed; system not in use. School closed; system not in use. System not in use. System not in use. Assumption: 50% of the BTU's produced are used to heat the school. The remaining BTU production is used for electrical generation and waste heat. Assumption: 50% of the BTU's produced are used to heat the school. The remaining BTU production is used for electrical generation and waste heat. Assumption: 50% of the BTU's produced are used to heat the school. The remaining BTU production is used for electrical generation and waste heat. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. For the months of January through March there was 33 after hour callouts. 90 % were fuel problems, either debris jamming up augers or ice blocks in the the fuel. The remaining issues were major in scope. One being a stack temperature probe failure, one being an auger feed motor disintigration, and one being a sight glass leak causeing demage to the low water control board. Turbine did not run the entire time but basically ran 90% of the time the boiler was in operation. All numbers listed above are estimates in that I no longer track the fuel burnt on a daily or monthly basis. I also do not track how many KW's I produce. The KW's are highly erratic in that they have an inverse relationship to the outside temperatures and I have no digital tracking capabilities to get a good average daily or monthly. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. We experience down time about four days per month due to breakage and or steam leaks. As for how many btus of heat provided we are not sure other than we displace about 50,000 gallons of fuel oil per year at the school the other structures heated have not been tracked. Since heat is a waste product of electrical generation we produce far more heat than we can possibly use and vent a great deal of it to the outside. All numbers are estimated in that we do not track the lbs of chips used or the KW's /btus produced. October, November, December Values imputed from 2014 & 2016 averaged values per month. 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 2% of gross generation. This value was estimated from ES 2011 and PCE Jan-Jun 2012 wind data for Unalakleet. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2014-03-05: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2014-03-05: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2014-03-05: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2014-03-11: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Turbine operated fine during January- starting on Feb 18th to March 1st we had no access to the turbine data, 4/8/16 to 7/13/16 Turbine was deactivated during upgrade of small generator governer system. Turbine was also deactivated during the issue with a failed battery in the Tower. It was put back in production in September, but no data link was available until 2 Dec.. Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE Net RE Generation is an imputed value based on the assumption that station service is 1% of gross generation. Net RE Generation is an imputed value based on the assumption that station service is 1% of gross generation. Net RE Generation is an imputed value based on the assumption that station service is 1% of gross generation. Net RE Generation is an imputed value based on the assumption that station service is 1% of gross generation. Net RE Generation is an imputed value based on the assumption that station service is 1% of gross generation. Net RE Generation is an imputed value based on the assumption that station service is 1% of gross generation. Net RE Generation is an imputed value based on the assumption that station service is 1% of gross generation. Net RE Generation is an imputed value based on the assumption that station service is 1% of gross generation. Efficiency reported as 10.3%. Actual diesel generation is 15,944 kWh. O&M costs derived from labor averages. ISER: Station service (4478 kWh) and diesel gross generation (15,944) were provided in REF Performance form. The RE station service was estimated based on the energy source distribution (69.3% Hydro, 30.7% Diesel). O&M costs derived from labor averages. ISER: Zero diesel gross generation during November. All reported station service subtracted from gross hydro generation. Efficiency reported as 10%. Actual diesel generation reported is 2,553 kWh. O&M costs derived from labor averages. Station service total 2,890 kWh. Gross total generation: 94% Hydro and 6% Diesel. Station service was adjusted based on the generation distribution. Down for maintenance 6/3 - 6/14 Whenever the plant is taken off-line for maintenance, it is usually off for extended periods while operators troubleshoot and wait for materials to arrive in Atka. There are load balance problems in Atka. Operators are at times running a diesel generator at the same time as the hydro-plant to balance the load. System is being operated manually. The City and AEA circuit rider program will visit Atka April, 2015 to work on diesel switchgear and to install SCADA. The hydro switchgear will be adjusted after the diesel plant work is done. Down 8/1 - 8/15 to repair small leak around bypass gate. Down 8/27 to 10/1 to install valve extension and other work. Problems with installing valve extension because it wouldn't fit. Everything returned to prior state and system started. Flow Transmitter at the school failed. Replaced the Power Supply. Actual fossil fuel quantity are in MMBtu. Actual fossil fuel price are in $/MMBtu. Due to language in contract actual landfill gas used and billed landfill gas use may be different. In January, billed landfill gas use was 31,395 MMBtu. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. Downtime in January due to the exhaust stack modification for each unit; each stack height was increased. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two price tiers. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.92 in February. Due to language in contract actual landfill gas used and billed landfill gas use may be different. In February, billed landfill gas use was 34,906 MMBtu. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.92 in March. Due to language in contract actual landfill gas used and billed landfill gas use may be different. In March, billed landfill gas use was 36,850 MMBtu. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. In March there was a 4K hour service to each of the engines requiring downtime. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.92 in April. Due to language in contract actual landfill gas used and billed landfill gas use may be different. In April, billed landfill gas use was 38,168 MMBtu. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.72 in May. Due to language in contract actual landfill gas used and billed landfill gas use may be different. In May, billed landfill gas use was 37,684 MMBtu. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.81 in June. Due to language in contract actual landfill gas used and billed landfill gas use may be different. In June, billed landfill gas use was 30,816 MMBtu. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. In June all of the units required a de-coking as well as their 6k hour maintenance service. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.8 in July. Due to language in contract actual landfill gas used and billed landfill gas use may be different. In July, billed landfill gas use was 34,464 MMBtu. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. In July, de-coking and 6k hour services of remaining engines was wrapped up. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.81 in August. Due to language in contract actual landfill gas used and billed landfill gas use may be different. Billed landfill gas use not yet available. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.81 in September. Due to language in contract actual landfill gas used and billed landfill gas use may be different. Billed landfill gas use not yet available. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. In September, a 5th engine was placed in operation. It did not get to run the whole month and in the evenings unexpectedly created more power than needed to deliver. Therefore, output had to tone down to accommodate the load. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.58 in October. Due to language in contract actual landfill gas used and billed landfill gas use may be different. Billed landfill gas use not yet available. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. * Accumulation of engine downtime hours ** Most repair costs were warranteed during operational year 2013. Remainder of repair costs are incorporated into the O&M totals. October's downtime occurred near the end of the month and was caused by a bus communication failure. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.59 in November. Due to language in contract actual landfill gas used and billed landfill gas use may be different. Billed landfill gas use not yet available. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. * Accumulation of engine downtime hours ** Most repair costs were warranteed during operational year 2013. Remainder of repair costs are incorporated into the O&M totals. Actual fossil fuel quantity is in MMBtu. Actual fossil fuel price is in $/MMBtu (Tier I price). There are two Tier prices. Tier I – for the first 31,000 MMBtu purchased Tier II – for the additional MMBtu (>31,000) purchased, Tier II price was $2.59 in November. Due to language in contract actual landfill gas used and billed landfill gas use may be different. Billed landfill gas use not yet available. Doyon receives payment to operate the gas processing plant and pipeline. Payment is in the form of a 2% 'discount' on the landfill gas price for the first 31,000 MMBtu purchased. * Accumulation of engine downtime hours ** Most repair costs were warrantied during operational year 2013. Remainder of repair costs are incorporated into the O&M totals. A failed motor/pump at the gas processing skid caused significant downtime in December. Corrected SS value based on O&M form. - avm 03/06/14 Revised FF Qty and Electric RE Efficiency based on values on O&M form. - avm 3/6/2014 RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) Revised Actual FF Qty with value from O&M form. -avm 03/06/2014 RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) Revised Actual Net Electricity to Secondary Loads based on value from O&M form - avm 03/06/2014 RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) Revised Actual FF Qty based on value on O&M form - avm 3/6/2014 RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) Actual net RE electric generation is an imputed value based on the assumption that station service is 3% of gross generation. The station service assumption was calculated as the average of the station service share with respect to gross generation based on the project's reported data for Jan to Jul, and Sept to Dec. RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) RE Electricity Generation reflects only the output of 1 of 4 wind turbines (1 REF, 3 non-REF) Corrected SS value based on O&M form. - avm 03/06/14 Corrected SS value based on O&M form. - avm 03/06/14 Corrected SS value based on O&M form. - avm 03/06/14 Corrected SS value based on O&M form. - avm 03/06/14 Corrected SS value based on O&M form. - avm 03/06/14 Corrected SS value based on O&M form. - avm 03/06/14 Corrected SS value based on O&M form. - avm 03/06/14 Corrected SS value based on O&M form. - avm 03/06/14 Corrected SS value based on O&M form. - avm 03/06/14 WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire WTG1 was brought back on line after extensive repairs, and painting, due to fire Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Quarter 1 - 2016. Converter controller problems plagued turbine 1 in Q1 2016. EWT installed all new converter communications components and the unit finally became operational in early March 2016. Turbine 2 ran well in Q1 2016. QUARTER 2-2016. Signifcant downtime for EWT1 due to several ground fault alarms from the power converter. KEA meggered generator and cables then reassembled unit. Test runs proved unit is now OK. EWT2 had downtime due to a bad blade battery that gave indications that cell voltages were OK. EWT semi-Annual maint visit performed April 22-24, 2016. Quarter 3 - 2016. Both EWT turbine performed very well except for several short duration problems with PLC-converter comms and blade battery packs. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 7.6% of gross generation. The parasitic load assumption was based on data reported for the project from Jan to Jun and Sep to Dec. Actual net RE electric generation is an imputed value based on the assumption that parasitic load is 7.6% of gross generation. The parasitic load assumption was based on data reported for the project from Jan to Jun and Sept to Dec. Data import 2015-04-21: gross generation was reported. Parasitic load was estimated based on an assumption of 12% of gross generation, and net generation was calculated based on that estimate. estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation estimated based on past monthly average net generation The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. The value in Actual Net Electricity to Secondary Load is the net electricity diverted to storage (acid batteries, value=energy input to the batteries- energy output from the batteries). avm 03/06/2014. Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Out of Service May 2011 through August 2011 Out of Service from May 2011 to August 2011. Out of Service from May 2011 to August 2011. Out of Service from May 2011 to August 2011. Out of Service from May 2012 to August 2012. Out of Service from May 2012 to August 2012. Out of Service from May 2012 to August 2012. Out of Service from May 2012 to August 2012. No generation from May 2013 thru September. Isolation for summer. No generation from May 2013 thru September. Isolation for summer. No generation from May 2013 thru September. Isolation for summer. No generation from May 2013 thru September. Isolation for summer. No generation from May 2013 thru September. Isolation for summer. based on average of actual data from January prior 5 years average of prior actual february 5 yrs average prior 5 years march average prior 5 years April average prior five years May average prior five years June average prior 5 years July average prior 5 years August average prior 5 yrs Sept average prior five years Oct average prior 5 yrs Nov average prior five years Dec Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. From REF O&M reports and PCE program data. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. From REF O&M reports and PCE reporting. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. From REF O&M reports and PCE program data. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE Data from PCE The Solar Water Heating System usually only runs from late May to mid September. The Solar Water Heating System usually only runs from late May to mid September. The Solar Water Heating System usually only runs from late May to mid September The Solar Water Heating System usually only runs from lat May to mid September. Solar Water Heating System only runs from late May to mid September. The Solar Water Heating System usually only runs from late May to mid September. The Solar Water Heating System usually only runs from late May to mid September. The Solar Water Heating System usually only runs from late May to mid September. The Solar Water Heating System usually only runs from late May to mid September. Project only runs late May to mid September. Project only runs late May to mid September. Project only runs late May to mid September. Project only runs late May to mid September. Project only runs late May to mid September. System typically does not operate in November. System typically does not operate in December. 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-06: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-01-08: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2015-04-14: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Data import 2016-01-07: gross generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and net generation was calculated based on that estimate. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Production for the site has run in line with previous years. While individual months, one year to the next, may vary by 50% of more, annual averages have stayed within 2 or 3% year to year. Progress has been made tuning up the icing control algorithms. Originally we shut down for 120 hours after icing was detected but now we leave it only hours and then see how the unit performs. If measured airflow and generation match the established power curve the unit runs up to full power. If it is mildly off it sustains a reduced load, and if it is well off it stays offline for a few more hours. Other sites have experienced blade bearing failures so we have installed a blade bearing monitoring system which automatically shuts down the unit if a fault is detected. The PMT low side breakers have had remote operators installed as an arc flash analysis indicated they could not be safely operated at the breaker. Production and curtailment are similar to previous years. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. Data input from data reported on GVEA website about EVA Creek Windfarm. Only kWh output totals known. 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-06: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-14: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2016-01-08: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. adding load regulator as a parasitic load. adding load regulator as a parasitic load. adding load regulator as a parasitic load. adding load regulator as a parasitic load. adding load regulator as a parasitic load. adding load regulator as a parasitic load. Actual Net Heat Output updated from imputed (494 MMBtu) to actual reported value. 01/28/2014 avm Actual Net Heat Output updated from imputed value (494 MMBtu) to reported values. 01/28/2014 avm Preventative Maintenance Actual Net Heat Output, Actual RE fuel quantity-chips, Biomass Moisture Content, Actual RE fuel price-chips updated per Performance Report received from Helen Traylor 01/28/2014 via email. 01/28/2014 avm Actual Net Heat Output updated from imputed value to actual reported value. 01/28/2014 avm We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. We had a number of Circ Pump failures in October and November. In November we replaced a number of screens and found several failures of the installer that we were not aware of. This resulted in downtime and extensive trouble shooting. In November it involved new pump kits and a 8 day downtime. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. The only downtime for the Thorne Bay wood-fired boiler time was in the summer months. Date: period from 1-1-16 to 7-31-16, no unscheduled maintenance scheduled regular maint included, filters, brushes & inspections During times of low system load one unit at time is off line PLC problem on unit 2 16 hrs downtime During the time period of 1-1-17 to 9-30-17 no unscheduled down time, unit downtime was scheduled to perform maintenance Organic Rankin Cycle - generates electricity from waste heat. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Grantee did not report to REF program. Data available through utility reporting to PCE program. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. From REF O&M report, and PCE program data. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. From REF O&M reports and PCE program data. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. From REF O&M reports and PCE program data. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2015-04-15: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. The heat recovery system was commissioned on February 16, 2016. It ran continuously until sometime in June 2016 due to low pressure cutoff. On October 13, 2016, the heat recovery loop was repressurized and operational. No leaks were found in the system. Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled NO issues with site, in Sept, NPS wanted to repitch blades, but found there was no room on the hub to manipulate the blade pitch any, and the job was cancelled Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Some communications failures, due to failed 24vdc power supplies, changed vendor and make of power supply,,, being done fleet wide Revised SS value based on O&M form. avm 03/06/2014 Revised SS value based on O&M form. avm 03/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 Revised SS value to match O&M form. -avm 3/06/2014 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross 1/13/2014: estimated net electric generation as 98% of gross Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Revised Actual Net RE Electric Generation to match value in O&M form. avm 03/06/2014 Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-05: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. Data import 2014-03-11: net generation was reported. Parasitic load was estimated based on an assumption of 2% of gross generation, and gross generation was calculated based on that estimate. 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Biannual testing and chemical adjustement of waste heat coolant. Fourth Quarter values are averages from previous years. Actual fossil fuel quantity for electric boiler: 156,313 kWh @ $0.1033/kWh Actual fossil fuel quantity for electric boiler: 136,418 kWh @ $0.1033/kWh Actual fossil fuel quantity for electric boiler: 128,104 kWh @ $0.1033/kWh Actual fossil fuel quantity for electric boiler: 107,971 kWh @ $0.1033 kWh Actual fossil fuel quantity for electric boiler: 72,145 kWh @ $0.1033/kWh Actual fossil fuel quantity for electric boiler: 60,549 kWh @ $0.1033/kWh Actual fossil fuel quantity for electric boiler: 59,758 kWh @ $0.1033 kWh Actual RE fuel quantity for electric boiler: 62,421 kWh @ $0.1033/kWh Actual fossil fuel quantity: 69,327 kWh @ $0.1033 kWh Actual fossil fuel quantity: 78,135 kWh @ $0.1033 kWh Actual fossil fuel quantity: 88,825 kWh @ $0.1033 kWh Actual fossil fuel quantity: 108,766 kWh @ $0.1033 kWh Unit taken offline 9/30 for Sitka Elec. School went online There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. There was no downtime due to mechancial issues. The City's teacher duplex housing utilizes one (1) Econoburn boiler and cord wood has been harvasted by the City of Tanana off the "Road to Tanana" easement. The City has mechanized the loading, transport, and splitting of the Road to Tanana forewood which has resulted in low cost per cord. The City is following GARN operating produres including annual testing the water within boiler. General Comments: Fires 3 times a day Works great no issues as of yet. General Comments: Fires 3 times a day Works great no issues as of yet. General Comments: Fires 3 times a day Works great no issues as of yet. General Comments: Fires 3 times a day Works great no issues as of yet. General Comments: Fires 3 times a day Works great no issues as of yet. General Comments: Fires 3 times a day Works great no issues as of yet. General Comments: Fires 3 times a day Works great no issues as of yet. General Comments: Fires 3 times a day Works great no issues as of yet. General Comments: Fires 3 times a day Works great no issues as of yet. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Actual fossil fuel quantity is the average fuel use during FY2013 per month. Changing data provided in the template to align with internal documentation provided by AVEC. Changed data from what was reported in template to reflect values in internal AVEC documents. Changed data from what was reported in template to reflect values in internal AVEC documents. Changed data from what was reported in template to reflect values in internal AVEC documents. Changed data from what was reported in template to reflect values in internal AVEC documents. Stetson contribution based on actual cooper lake generation and assumption of contribution of 6020 mwh annually Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Repairs to heat loop in June to prevent backfeed of heat from buildings. Software program glitch - replaced Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . Chevak WTG1 0020 had a generator failure and awaited engineering and repairs. One coil was cut out and bypassed. Generator creates approx 2% less power a month . some communications faults and failures,,,, maint scheduled for end of May,,,,,,, ss 05/25/17 some communications faults and failures,,,, maint scheduled for end of May,,,,,,, ss 05/25/17 some communications faults and failures,,,, maint scheduled for end of May,,,,,,, ss 05/25/17 some communications faults and failures,,,, maint scheduled for end of May,,,,,,, ss 05/25/17 some communications faults and failures,,,, maint scheduled for end of May,,,,,,, ss 05/25/17 some communications faults and failures,,,, maint scheduled for end of May,,,,,,, ss 05/25/17 some communications faults and failures,,,, maint scheduled for end of May,,,,,,, ss 05/25/17 some communications faults and failures,,,, maint scheduled for end of May,,,,,,, ss 05/25/17 Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. Most of the down times I know about were caused by operator error in that large rocks and in one case a brick were scooped up fed into the boiler. I think there was approximately four weeks of down time for the three instances I know about. We successfully burnt material that was at 35% moisture content by speeding up feed rates, however btu production from such material was not adequate at extreme cold temperatures. Material that was closer to 20 worked better. There was one instance where a power outage caused the fire to go out then when the power resumed the burn box was plugged with chips breaking the burn pot. Rex Goolsby added a control that solved that problem from ever occurring again. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. In February 2016, we became aware of a hole in a blade on EWT-1 turbine, and in consultation with the manufacturer were instructed to shut the unit down. When they were able to bring maintenance personnel in to evaluate, initially we were led to believe the repair effort would be minor and was simply delayed by environmental conditions. Subsequently, in May 2016, we were advised the problem was much more significant and was not covered by the maintenance-service agreement. At that time we contacted our insurance company and began working on plans to have the blade repaired. The unavailability of a crane in Nome required us to instead find a company and arrange to have the repair done without removing the blade (and even if a crane had been available, EWT had no procedure for removing a single blade). The repair was completed and the unit returned to production in August 2016. Other than this significant issue, the units performed relatively consistent with other downtime associated with environmental factors (wind vanes, anemometers, etc.). NJUS has a maintenance agreement with EWT with repair being part of the agreement; hence, we are indicating these smaller items as "warranty" although NJUS personnel try to also provide assistance to maximize availability, but some issues require EWT to ship technicians in from other locations. Supervisory personnel are used to provide this assistance and their time is not allocated between production units. Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Data input from monthly calculation spreadsheet provided Fuel price from PCE report Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, Data was calculated using remote monitoring waste heat supply and waste heat return to pp, Assumed flow rate of 20, RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. RM Sensors were down Oct.- December, but the community only burned 8 gallons of fuel for those three months. System was finaly operational in July, we have been able to monitor since then, So far the heat recovery has provide all heating to the school our boilers have not run since the system went on line. We currently have the agreement in place with AVEC and our monthly cost is rated at $3,447.58 each month we would normally burn between 4-5 thousand gallons of fuel this time of year so we are saving significant dollars as well as displacing fuel we do not have to burn. We have minimal O&M costs on our side of the system, we have 2 pumps and the heat exchanger that are part of our monthly maintenance schedules and is built into our budget for the entire school. System was finaly operational in July, we have been able to monitor since then, So far the heat recovery has provide all heating to the school our boilers have not run since the system went on line. We currently have the agreement in place with AVEC and our monthly cost is rated at $3,447.58 each month we would normally burn between 4-5 thousand gallons of fuel this time of year so we are saving significant dollars as well as displacing fuel we do not have to burn. We have minimal O&M costs on our side of the system, we have 2 pumps and the heat exchanger that are part of our monthly maintenance schedules and is built into our budget for the entire school. System was finaly operational in July, we have been able to monitor since then, So far the heat recovery has provide all heating to the school our boilers have not run since the system went on line. We currently have the agreement in place with AVEC and our monthly cost is rated at $3,447.58 each month we would normally burn between 4-5 thousand gallons of fuel this time of year so we are saving significant dollars as well as displacing fuel we do not have to burn. We have minimal O&M costs on our side of the system, we have 2 pumps and the heat exchanger that are part of our monthly maintenance schedules and is built into our budget for the entire school. System was finaly operational in July, we have been able to monitor since then, So far the heat recovery has provide all heating to the school our boilers have not run since the system went on line. We currently have the agreement in place with AVEC and our monthly cost is rated at $3,447.58 each month we would normally burn between 4-5 thousand gallons of fuel this time of year so we are saving significant dollars as well as displacing fuel we do not have to burn. We have minimal O&M costs on our side of the system, we have 2 pumps and the heat exchanger that are part of our monthly maintenance schedules and is built into our budget for the entire school. Green Lake Hydro and Jarvis Diesel provide Sitka Generation in addition to Blue Lake Hydro We just started the system in August and so we were just burning and really just warming the building water. We were training also, in September it started to burn more but still not much demand. In October we had to empty the silo to get the scales certified and the OXY sensor went out so we had to order a new one. So November was our first month of really using the system and it is running real good and we are just getting up to burning 500 to 6000 pounds of pellets in a 24 hour period. We just started the system in August and so we were just burning and really just warming the building water. We were training also, in September it started to burn more but still not much demand. In October we had to empty the silo to get the scales certified and the OXY sensor went out so we had to order a new one. So November was our first month of really using the system and it is running real good and we are just getting up to burning 500 to 6000 pounds of pellets in a 24 hour period. We just started the system in August and so we were just burning and really just warming the building water. We were training also, in September it started to burn more but still not much demand. In October we had to empty the silo to get the scales certified and the OXY sensor went out so we had to order a new one. So November was our first month of really using the system and it is running real good and we are just getting up to burning 500 to 6000 pounds of pellets in a 24 hour period. We just started the system in August and so we were just burning and really just warming the building water. We were training also, in September it started to burn more but still not much demand. In October we had to empty the silo to get the scales certified and the OXY sensor went out so we had to order a new one. So November was our first month of really using the system and it is running real good and we are just getting up to burning 500 to 6000 pounds of pellets in a 24 hour period. We just started the system in August and so we were just burning and really just warming the building water. We were training also, in September it started to burn more but still not much demand. In October we had to empty the silo to get the scales certified and the OXY sensor went out so we had to order a new one. So November was our first month of really using the system and it is running real good and we are just getting up to burning 500 to 6000 pounds of pellets in a 24 hour period. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. 150 gallons of diesel were used for the boiler from January 2016 to March 2016 while one of the heat pumps was down. One of the heat pumps had a bad compressor and it was down from January until the end of March. This was a warranty item and there was no cost to replace. $9,024 per kilowatt hour spent on electricity to run the geothermal heat pump system from beginning of January 2016 to end of October 2016. The system needed to be shut down twice during cold snaps when it could not meet demand. The only repairs necessary included the replacement of two taco valves. Historical fuel receipts from pre-geothemal installation show that $54,300 was spent on fuel oil for the 12 month period from July through June 2011/2012. The records for the 12 month period from July through June 2012/2013 shows a total of $51,110. The combined average for these two years equals $52,705. After installation of the geothermal heat pump our fuel oil receipts show a total of $3,625 for 2015 and $3,854 for 2016 which is a 93% decrease and average savings of 49,000 per year. For 2016 we have only used 150 gallons of diesel. This was used from January to the end of March while one of the heat pumps was down due to a bad compressor. The oil fired boiler was shut off once the heat pump was repaired at the end of March and was not turned on again until November. For 2016 we have only burned $567.00 of fuel. This is a savings of $52,138 for 2016 or a 99% decrease in expenses. Our meter reading for total KWh to run the heat pumps totalled 60,153 hours for 2016. At .15 cents per KWh based upon Homer Electric current rates the total to operate the heat pump in 2016 equals $9,024. electric_efficiency_after_re_integration 80 80 14 14 13.9 14 14.1 14 13.2 12.1 12.2 13.9 13.2 12.9 13.6 14 14 14 12.9 12.4 12.2 13.6 14 12.1 12.1 12.9 14 13.7 13.7 13.7 14.5 14 14.3 12.9 13.8 13.8 13.5 13.8 13.4 13.3 13.7 12.9 13.7 13.7 12.8 13.8 12.9 13.3 13.7 12.8 12.9 13.4 13.6 14.5 14 13.5 13.7 13.7 14 13.8 14.1 14 13.9 14.1 14.1 14.3 13 13.8 13.8 14.4 11.9 9 4.6 21.2 5 15.1 31.7 2 13.2 12.4 25.4 5.9 45.7 16.4 17.5 16.5 17.6 15.9 17.8 16 15.3 17.1 15 16.3 16.8 14.6 17.6 16 17.6 17.1 17.8 16.1 16 18.4 14.9 16.6 15.8 16.8 16.2 16.5 15.4 15 17 15 15.7 13 18.1 14.6 14.9 16.5 14.7 15.3 15.4 15.7 14.7 15.9 12.9 16.1 15.3 16.9 14.8 16.7 19.8 14.9 17.5 16.5 15.8 14.4 16.7 17 16.9 13 13 13.4 13.1 13.2 13.4 14.1 13.5 14.2 13.5 13.5 14.7 13.5 15.7 15.7 15.7 15.7 17.5 15.4 15.7 19.5 15.7 15.4 14.9 15 16 16 15.4 15.8 15.5 15.4 15.4 15.4 15.1 15 14.8 15 14.9 14.9 14.7 14.8 15.4 15.4 15.3 15.3 15.3 15.2 15 15.2 14.7 14.4 14.9 14.9 14.9 15 14.8 15.2 14.7 14.5 15.3 15.5 15.5 15.5 15.2 15.2 14.6 15.2 15.4 14.9 15 15.2 49.5 40.1 23.8 30.8 31.1 15.9 17 22.8 21.4 12.8 12.9 9.4 10.1 7.8 16.6 6.4 11.2 11.5 9 5.6 10.8 8.4 9.4 9.2 9 9.1 3.1 80 13.4 13.6 13.6 11 12.7 12.9 12.7 12.8 13 14.2 14.6 14.8 15.2 14 14.3 15.1 13.7 14 13.4 13.6 13.9 14 11.3 15.6 14 13.8 13.9 13.3 12.2 13.1 12.6 13.6 13.8 12.7 13 12.4 13.2 13.9 13.9 13 12.6 14 13.8 13.5 14.3 13 14.1 14.2 13.5 13.8 15.1 14.8 13.9 15.6 14.7 15.1 14.6 14.3 15.1 14 13.7 13.8 13 12.9 13.3 13.3 13.5 13.1 13.2 12.7 13.4 13.9 15.6 17 18.2 16.3 12.9 13.3 19.8 12.9 13.8 13.1 13.4 13.4 13.7 13.7 13.6 13.8 14.6 13.9 13.9 13.2 14 14.3 14.4 13.7 13.6 13.4 13.7 14 14.4 13 13.8 13.8 12.5 14.2 13.5 13.9 13.6 13.6 13.3 13.6 13.1 14.5 13.7 14 13.6 14 13 13.6 13.8 13.4 13.6 13.7 13.6 13.7 13.9 13.5 12.9 14.2 14 14.1 13.9 13.2 14.3 13.4 13.4 14.5 13.3 14 13.3 14.3 13.6 14 13.5 13.7 14.3 14.4 13.3 12.1 13.6 14 14 11.7 13.8 13.9 13.7 13.9 14.4 14.9 15.1 16.4 15.5 16.8 14.3 14.5 13.9 13.6 13.6 14.1 14 13.9 14.5 14 13.9 13.5 13.2 14.6 14.5 12.8 13.5 13.4 13.8 13.6 15.6 13.7 13.8 14 13 13 13.4 13.7 13.8 14.1 13.2 13 13.5 15.1 12.4 13.1 12.7 12.2 11.5 11.6 12.7 11.7 13 12.1 13.2 13.9 14.1 13.3 12.1 12 12.6 12.1 11.9 11.3 11.7 12.5 13.2 14.4 12.4 12.6 11.5 13.4 13.8 13.4 13.9 12.3 14.5 14.3 14.2 12.6 13 12.7 13.3 12.7 12.5 12.7 16.3 11.7 14.9 14.4 15 13.6 14.6 14.3 13 13.2 13.2 12.6 12.8 12.2 12.8 15.3 15.1 15.1 15 15.2 14.9 14.7 14.5 14.5 14.3 14.1 14.2 14 14.4 14.3 14.3 14.2 16.3 13.7 14.2 12 13.4 16.4 16.9 11.8 18.1 13.6 14.2 14.6 15.6 14.1 14.8 14.1 15.2 13.5 15.7 14.2 17.4 13.2 14.5 15.5 14.4 16.5 14.7 12.4 14.6 15.3 15.3 15.6 15.9 15.6 12.7 14.9 14.8 16.6 12.5 14.3 14.3 14.9 15.4 14.1 14.4 16.3 16 15.7 16.1 15.9 15.2 14.5 14.5 15.1 15.2 15.8 16 15.5 16.2 15.9 16 14.8 11.2 13.4 11.5 13 16.4 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 13.6 15.5 13.7 13.3 11.7 12.7 13.5 15.2 15.2 15.2 14.2 15.5 13.6 14.8 15.3 7 15.1 7 14.8 14 15 15 15.3 14.8 15 24.4 13.4 18.2 14.4 10.6 11.9 51.1 14.2 22.3 11.4 16.7 15.4 10.1 17.7 0 16.3 0 15 10.6 18 42.2 0 11.1 18.4 14 22.3 16.6 15.8 15.8 16.6 15.8 10.7 13.3 12.8 13 12.9 13.7 13.8 13.4 13.9 13.4 13.3 12 11.8 14.3 11 13.3 13.7 14.3 13.9 11.7 10.4 12 11.9 13.6 13.2 13.9 15.8 11.9 11.2 13.5 12.9 13 12.3 12.5 9.1 17 12.1 12.3 12.1 12.4 12.3 11.8 23.3 12.2 12.2 12.1 11.9 14.2 14.2 14.2 16.3 16 15.7 16.1 15.9 15.2 14.5 14.5 15.1 15.2 15.8 16 15.5 16.2 15.9 16 14.8 11.2 13.4 11.5 13 16.4 12.2 12 13.6 13.9 14.3 13.5 13.7 14.4 13.4 12.7 11.7 12.9 11 12.6 12.6 12.6 12.3 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.4 12.2 13.4 13 12.8 10.6 12 12.4 12.7 13.1 12 11 12 13.1 12.8 12.6 11.5 13.9 12.8 12.9 13.9 13.5 13 13.2 12.3 12.9 12.4 12.8 12.6 12.6 12.9 13.6 12.6 12.8 12.7 13.4 12.9 12.5 13.3 12.6 13.9 6.5 20.3 13.8 13.7 12.5 13 12.9 12 12.5 11.7 12.3 12.5 12.4 11.9 11.5 14.1 12 12.5 12.5 13.1 11 15.9 13.6 13 12.3 11.8 12.5 13.5 12.5 12.2 11.4 12.1 11.1 11.8 9.7 11.6 11.1 9.1 11.3 9.1 11.2 12.3 9.7 11.5 10.8 10 11.6 10.7 11 8.2 11.5 11.4 9.5 11.3 9.4 11.3 10.9 9.4 11.6 11.4 11 9.2 11.6 11.4 9.3 11.4 12.3 9.3 10.9 13.3 9.2 11.4 10.9 8.9 11.3 10.8 9.2 11 9.1 14 13.3 13.8 14 14.3 13.2 14.2 14 13.1 12.8 13.1 12.6 11.6 11.6 12.6 13.4 13.1 12.6 12.6 12.6 12.9 12.3 12.8 13.6 12.8 13.4 12.4 12.6 11.6 12.6 12.9 11.8 14.7 11.8 13.1 13.6 12.5 13.1 12.2 12.5 12.4 13.3 14 11.6 13.6 13 13.9 12.8 12.4 11.9 17.8 13.3 12.3 13 12.4 14.2 13.3 14.6 15 15.4 14.8 14.9 15.6 14.7 15.8 14.7 14.8 14.4 15 17.2 14.4 14.4 14.5 14.5 15 14.2 14.8 13.9 13.5 13.8 13.4 13.1 13.5 12.6 13.5 14.6 15 12.1 13 11.8 13.1 13.3 13 14.6 13.4 13.3 13.7 14.1 13.3 13.2 13.9 12.7 13.3 14.2 13.2 14.5 12.4 13.1 12.5 15.1 14.7 12.6 14.5 13.3 12.8 12.9 13.5 13.5 13.4 12.4 12.9 12.4 12.1 12.9 12.8 13.1 13.8 12.9 13.3 13.7 15.1 16.3 18.9 16.5 17.2 13.3 13.4 13.2 12.7 12.6 13.2 13.8 13.7 13.3 13.8 13.7 14.3 14.3 14.6 14.8 13.8 14.1 14.2 14.5 14 14 13.7 13.5 13.5 18.4 13.3 14.9 13.7 13.3 14.1 13.9 14.3 14 13.7 13.5 13.5 18.4 13.3 14.9 13.7 13.3 14 13.9 13.9 15.2 14.4 13.9 13.9 13.7 13.4 13.5 13.5 12.8 13.6 14.2 14.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 12.7 13.8 12.3 13.2 12.6 12.5 12.6 12.6 9.9 13.3 12.9 13 12.9 12.8 12.6 13.5 13.1 13.4 12.8 12.8 12.9 12.8 12.2 13.3 13.3 12.9 12.8 12.5 12.8 12.2 12.1 12.3 12.5 12.7 12.8 13.2 15.1 15.2 14.7 14.9 14.8 14.9 14.8 14.9 14.7 15 15.3 15.2 14.9 15.1 14.8 15.2 15 15.3 15 15.6 15.9 14.7 14.6 15.4 11.7 11 11.9 11.4 11.2 11.6 13.1 13.1 11.6 11 12 12.4 11.6 11.9 12.9 12.3 13.4 12.8 11.9 11.5 11.6 12.3 12.3 13.1 12.4 11.5 11.6 11 11.7 12.4 12.2 12.1 14.4 13.3 13.8 14.2 12.8 13.7 12.6 13 12.6 13.3 12.3 13.4 13.3 12.7 13.7 13.2 13.3 13.6 12.4 12.7 12.5 11.9 13 12.5 12.6 12.2 12.5 12.6 13.2 12 12.1 12.4 12.4 12.6 13.4 18.5 17.1 14 17.1 13.1 12.6 11.4 13.2 12.5 12.3 12.7 11.2 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 15 15.7 13 18.1 14.6 14.9 16.5 14.7 15.3 15.4 15.7 14.7 15.9 12.9 16.1 15.5 16.9 14.8 16.5 15.9 15.9 16 15.5 14.6 15.1 15.7 15.6 16.3 15.8 15.5 17.2 16.4 15.4 17.3 15.1 16.1 15.4 14.1 15.7 14.5 15.9 15.9 12.7 14.1 14.2 13.8 13.9 12.8 14.4 15.1 12.9 13.7 13.6 13.4 13.8 13.8 14.8 15.1 15.2 15.2 15.9 13.9 13.2 12.6 12.5 13.3 40.7 40.7 40.6 month 10 11 12 1 2 3 4 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 10 11 12 1 2 3 4 5 7 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 6 7 8 9 10 11 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 1 2 3 4 5 6 7 8 9 10 11 12 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 1 2 3 4 5 6 7 8 9 10 11 12 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 3 9 10 1 2 3 4 5 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 1 2 3 4 5 6 7 8 9 10 11 12 9 10 11 12 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 7 8 9 10 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 nonscheduled_maintenance_hours 4 3 144 2 1 432 720 3 48 12 180 11 61 58 11 69 11 177 250 1000 41 12 100 34 25 96 87 10 31 91 13 156 587 322 168 626 3 18 3 11 2 1927 414 437 362 30 8 5 214 28 71 175 40 47 54 58 60 3 943 45 36 89 86 24 60 10 0 48 0 230 1 3 720 2 12 0 696 5472 notes Data is sourced from PCE and historical performance. Data is sourced from PCE and historical performance. Data is sourced from PCE and historical performance. Data is sourced from PCE and historical performance. Data is sourced from PCE and historical performance. Data is sourced from PCE and historical performance. Data is sourced from PCE and historical performance. Data is sourced from PCE and historical performance. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated based month's data in previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated from previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Data from PCE. Parasitic load estimated based on previous years. Imputed as average generation of previous year for month, scaled by relative generation of this year to previous years. Generation efficiency from September Imputed as average generation of previous year for month, scaled by relative generation of this year to previous years. Generation efficiency from September. Imputed as average generation of previous year for month, scaled by relative generation of this year to previous years. Generation efficiency from September 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages parasitic load calculated from 2013-2016 monthly averages 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. parasitic load calculated from monthly average from 2011-2016 parasitic load calculated from monthly average from 2011-2016 parasitic load calculated from monthly average from 2011-2016 parasitic load calculated from monthly average from 2011-2016 parasitic load calculated from monthly average from 2011-2016 parasitic load calculated from monthly average from 2011-2016. adding load regulator as a parasitic load. parasitic load calculated from monthly average from 2011-2016. adding load regulator as a parasitic load. parasitic load calculated from monthly average from 2011-2016. adding load regulator as a parasitic load. parasitic load calculated from monthly average from 2011-2016. adding load regulator as a parasitic load. parasitic load calculated from monthly average from 2011-2016. adding load regulator as a parasitic load. parasitic load calculated from monthly average from 2011-2016. adding load regulator as a parasitic load. Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 Values imputed from 2013-2016 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. Data from PCE. Parasitic values based on average of previous years for the month. November performance estimated using heat recovery rates from prior 2016 months. December performance estimated using heat recovery rates from prior 2016 months. Electricity consumption and thermal output estimated based on previous years. Electricity consumption and thermal output estimated based on previous years. Electricity consumption and thermal output estimated based on previous years. From RCA filing. Parasitic load from average of previous years. From RCA filing. Parasitic load from average of previous years. From RCA filing. Parasitic load from average of previous years. From RCA filing. Parasitic load from average of previous years. From RCA filing. Parasitic load from average of previous years. From RCA filing. Parasitic load from average of previous years. Assume that reported value for Turbine 2 (113,563) was typo or off by an order of magnitude--this would be physically impossible. Changed to 11356 fuel costs are taken from hooper bay for 2017. fuel values imputed from Hooper Bay, as values for this community were not available in DCRA fuel survey fuel values imputed from Hooper Bay, as values for this community were not available in DCRA fuel survey fuel values imputed from Hooper Bay, as values for this community were not available in DCRA fuel survey fuel values imputed from Hooper Bay, as values for this community were not available in DCRA fuel survey fuel values imputed from Hooper Bay, as values for this community were not available in DCRA fuel survey fuel values imputed from Hooper Bay, as values for this community were not available in DCRA fuel survey fuel values imputed from Hooper Bay, as values for this community were not available in DCRA fuel survey Reported values reduced by 1000 times to make values consistent with modeled values and past performance of the project. Reported values reduced by 1000 times to make values consistent with modeled values and past performance of the project. Reported values reduced by 1000 times to make values consistent with modeled values and past performance of the project. Reported values reduced by 1000 times to make values consistent with modeled values and past performance of the project. Reported values reduced by 1000 times to make values consistent with modeled values and past performance of the project. Reported values reduced by 1000 times to make values consistent with modeled values and past performance of the project. modeled economic data used for four months. modeled economic data used for four months. Data entered from the economic model and based on four months. modeled economic data used for four months 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. 2016 performance data sourced from PCE. Used PCE data. Station service an average from year. Used PCE data. Station service an average from year. Used PCE data. Station service an average from year. parasitic_load 1544 781 1671 1443 1467 1551 1930 1989 2040 1884 1665 1804 1522 5468 4931 2873 3475 3060 1540 1010 481 540 620 1310 1066 6749 7291 4853 3161 6834 2980 2566 2822 3116 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 6318 6108 5491 4868 4356 3926 2955 3405 3528 4524 6738 6272 0 0 0 0 0 0 0 0 0 0 0 0 946 979 773 1218 1074 842 849 1291 1138 1101 949 12379 1167 1224 1363 1197 755 1248 1559 1715 1948 1782 1296 447 803 1669 360 2350 5768 5351 5581 4744 4505 2875 720 724 4469 3802 2002 605 7402 5791 2889 2260 3675 7005 3102 2064 7510 1704 1360 1742 2878 2427 1563 4006 4267 2295 2424 2506 3957 2549 2291 3015 4156 3326 1390 1213 3092 5143 3301 1460 4090 4594 3007 5329 5768 3032 1873 4648 3456 1084 3412 1219 2440 1559 818 2948 3287 1946 946 2480 4057 3456 1539 5462 1143 8540 8011 12307 4622 8468 6231 2263 785 631 658 775 794 4740 2980 2690 6727 10317 7374 4146 3398 15015 11885 3905 6836 7145 14049 8004 13702 6655 7928 8574 14206 3991 11468 12135 5852 15296 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637 637 637 637 637 637 637 637 637 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 645 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 654 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 690 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 694 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 710 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 711 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 740 747 747 747 747 747 747 747 747 747 747 747 747 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 757 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 758 761 761 761 761 761 761 761 761 761 761 761 761 761 761 761 761 761 761 761 761 764 764 764 764 764 764 764 764 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 770 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 786 837 837 837 837 837 837 837 837 837 837 837 837 839 839 839 839 839 839 839 839 839 839 839 839 841 841 841 841 841 841 841 841 841 845 845 845 845 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 846 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 854 875 875 875 875 875 878 878 878 878 878 878 878 878 878 878 878 878 project__electric_efficiency_prior_to_re_integration 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 13.005 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 16.25 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13.84 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.09 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 15.48 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 13.19 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 8.66 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 14.11 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 13.62 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 14.8 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 13.9 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14.83 14.83 14.83 14.83 14.83 14.83 14.83 14.83 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 16.37 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 project__electric_generation_fuel_displaced True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True 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True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True project__goal_net_heat_delivered 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 1353 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1978 1978 1978 1978 1978 1978 1978 1978 1978 1978 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 11350 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 67960 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 2273784 project__goal_net_re_electric_generation 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 1700000 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True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False False True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True 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7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 7/1/2015 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 10/7/2014 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 11/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 10/1/2013 8/31/2015 8/31/2015 8/31/2015 8/31/2015 8/31/2015 8/31/2015 8/31/2015 8/31/2015 8/31/2015 8/31/2015 8/31/2015 8/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 12/31/2015 9/1/2015 9/1/2015 9/1/2015 9/1/2015 9/1/2015 9/1/2015 9/1/2015 9/1/2015 9/1/2015 9/1/2016 9/1/2016 9/1/2016 9/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 12/20/2014 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 8/1/2016 8/1/2016 8/1/2016 8/1/2016 8/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 1/1/2016 project__project_notes Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) Electric generation efficiency prior to RE integration not reported. Used the REF Model VII assumption of 13 kWh per gal. (AVM, 01/13/2013) The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The line to Naukati was energized on January 27th at noon. Work continues of pole placement. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. The project is for a plant that processes wood, not a burning system. A 100% efficiency is used for prior and after RE integration, in effect negating efficiency to factor into the displacement and savings estimates. Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Efficiency generation efficiency prior to RE integration not reported. Used REF Model Round VII assumption of 13 kWh per gallon. (AVM, 01/13/2013) Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Diesel heating system efficiency prior to RE integration is an assumption. Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Project Manager: Helen Traylor Installed Capacity: 7 MW (Five Jenbacher J420 1.4 MW units) Electric generation efficiency prior to RE integration is an assumption: weighted average of 2011 NG efficiency by AML&P from Alaska Energy Statistics Report Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. Quinhagak secondary load is not value added. Heating system efficiency is unknown. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. This project added a fourth turbine to the three already installed. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Application 870 was funded to install an electric boiler at the ANTHC facilities as a secondary load. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Generator efficiency is taken from the first reported performance data and is not prior to the installation of the wind farm. Applicatior 803 was partially funded and will add three GE 1.5 MW turbines and a battery in 2012. Expected completion date for the expansion is 12/31/12. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Prior to the solar system, an electric water heater was in use. Original analysis was done assuming displacement of electricity (from GVEA). Assuming displace DFO for GVEA. Electric generation efficiency prior to RE integration reflects GVEA's average efficiency from DFO in 2011. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Project will be fully commissioned after secondary loads are installed Q3 2012. Its unknown at this time if the secondary loads will be value added. Application 878 to install two more turbines was not recommended for funding because the wind resource in Emmonak is Class 2. The original project was recommended for funding based on the wind class in Nunam Iqua. The wind resource report came out after the four turbines in Emonnak were constructed. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. Electric generation efficiency prior to RE integration is the assumption used in the REF Model VII. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. This project will reduce heat recovery from the diesel powerhouse by an unknown amount. The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich Project Manager - Devany Plentovich project__project_operation_start_date 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 10/11/2010 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DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO project__electric_generation_fuel_displaced_type__conversion_factor_mmbtu 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 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73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 70.88 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 project__electric_generation_fuel_displaced_type__name Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel 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Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate 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Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel 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Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel 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Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel 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Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel 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Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha Naphtha 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City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Wrangell, City of Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co Gustavus Electric Co 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Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric 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Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric 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Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private 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Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility Private Electric Utility project__technology_type__id 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 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BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT 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HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS 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RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT WIND TO HEAT HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND WIND HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HEAT RECOVERY HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV SOLAR PV BIOMASS BIOMASS BIOMASS BIOMASS BIOMASS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS HEAT PUMPS id 1405 1406 1407 1408 1604 1605 1606 1607 1608 1609 1610 1611 1612 2131 2132 2133 2622 2623 2624 2625 2626 2627 2628 2629 2630 2631 2632 2633 3544 3545 3546 3547 3548 3549 3550 3551 3552 3553 3554 3555 1417 1418 1419 1420 1421 1422 1423 1427 1424 1425 1426 1690 1691 1692 1693 1694 1695 1696 1697 1698 2232 2233 2234 2646 2647 2648 2649 2650 2651 2652 2653 2654 2655 2656 2657 3592 3593 3594 3595 3596 3597 3598 3599 3600 3601 3602 3603 2192 2191 2190 2189 2188 2187 2186 2141 2142 2143 2144 2145 2682 2683 2684 2685 2686 2687 2688 2689 2690 2691 2692 2693 3640 3641 3642 3643 3644 3645 3646 3647 3649 3650 3651 1414 1415 1416 1672 1673 1674 1675 1676 1677 1678 1679 1680 2005 2006 2007 2248 2249 2250 2251 2252 2253 2254 2255 2256 2257 2258 2259 3688 3689 3690 3691 3692 3693 3694 3695 3696 3697 3698 3699 project__name Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Whitman Lake Hydro Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Terror Lake Unit 3 Hydroelectric Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Stetson Creek Diversion/Cooper Lake Dam Facilities Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project Blue Lake Hydroelectric Expansion Project actual_ff_om_hours actual_ff_om_price actual_ff_price 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.23 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 4.06 3.2 3.2 3.2 3.21 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 actual_ff_quantity actual_gross_re_electric_generation 267687 925413 431854 906084 1318845 748864 525388 507628 625590 68079 396643 863602 833761 1261541 1027731 650759 479811 1260875 626027 1114479 833462 542778 538630 290316 593027 530268 500566 407474 668001 496245 405435 785076 997956 804968 709676 1379213 962261 923845 457469 875142 3249000 4393000 3522000 4967000 3364000 339900 3706000 4513000 3868000 2268000 2265000 9702800 11649000 12134000 11879000 8769000 11554000 9401800 12512000 12512000 1116100 10437000 7961000 7807000 11734000 11915000 10210000 9989000 10187000 8987000 12084000 11014000 12267000 9913000 9304000 11045000 15815000 13958000 10215000 10729000 9628000 10433000 12959000 12015000 13051000 9870000 8278000 0 0 0 0 0 0 0 501790 473391 697592 685481 635434 635465 281938 111011 258345 393163 525317 821073 501790 473391 697592 685481 635434 4309 3574 0 1803 6352 7022 1978 48 25 183 1033 272000 2674000 5809000 5380000 4724000 3111000 4534000 4228000 4260000 5173000 5355000 5253000 5396000 5794000 6864000 6303000 4190000 5294000 3906000 6573000 4824000 4369000 6499000 3291000 6062000 8736000 9712000 6307000 3157000 6463000 4840000 4347000 5052000 4691000 3806000 4009000 5390000 6638000 5510000 actual_net_electricity_to_secondary_loads actual_net_heat_output actual_net_heat_to_secondary_loads actual_net_re_electric_generation 260956 908887 419857 897182 1311516 744046 519617 502228 620422 61499 391917 858359 828673 1255695 1022689 645633 472774 1254946 620242 1109133 828056 538541 533547 285426 588484 525200 493499 399617 659062 488614 395348 775358 988746 798318 703772 1373364 957599 917748 449700 865725 3219958 4362170 3494552 4944307 324554 4492811 3840769 2244789 2240448 9603000 11547900 12039400 11778700 8697800 11493600 9356000 12461400 12444700 418700 10335700 7867500 7714100 11624000 11830600 10134900 9924000 10127200 8935700 12022300 10959300 12195200 9817600 9199200 10929900 15711400 13854600 10136300 10641500 9567000 10381600 12904300 11952800 12971100 9772000 8191100 0 0 0 0 0 0 0 501790 473391 697592 685481 635434 635465 281938 111011 258345 393163 525317 821073 501790 473391 697592 685481 635434 4184 3451 -114 1581 6265 6968 1924 8 -25 88 917 272000 2674000 5809000 5292000 4640000 3025000 4464000 4165000 4205000 5119000 5301000 5197000 5337000 5730000 6797000 6239000 4128000 5232000 3849000 6517000 4774000 4317000 6449000 3224000 5993000 8676000 9643000 6306914 3156913 6462914 4839939 4346942 5051942 4690951 3805952 4008945 5389925 6637922 5509926 actual_re_fuel_price_chips actual_re_fuel_price_cords actual_re_fuel_price_electricity actual_re_fuel_price_pellets actual_re_fuel_quantity_chips actual_re_fuel_quantity_cords actual_re_fuel_quantity_electricity actual_re_fuel_quantity_pellets actual_re_om_hours 162 270 221 131 100 112 125 254 153 152 212 132 277 233 217 126 54 76 45 102 133 80 130 135 107 129 129 94 271 102 81 76 105 91 124 471 458 540 394 379 373 263 225 324 360 446 432 531 407 566 452 853 435 359 419 356 336 336 368 actual_re_om_price actual_total_other_ff_om_costs actual_total_other_re_om_costs 3872.94 9564.34 20244.44 18387.93 9255.53 26073.42 4228.44 4521.92 22998.95 23549.63 5572.8 30651.46 6018.97 5122.33 30118.69 6610.4 9513.64 23761.61 13513.41 14834.89 23903.15 24141.96 8705.4 95332.1 2597.06 17227.4 9411.63 15767.48 8896.12 18135.19 1410.69 3333.89 8498.27 27318.46 14065.76 8217.18 21394.06 4947.18 11085.26 38092.58 6904.34 94480.93 13281.56 3094.25 1020.53 2006 2010 168 alternate_total_actual_ff_om alternate_total_actual_re_om 3555.46 6382.08 2833.96 7027.86 8409 9042 22017 4838 6150 9299 23290 13052 32835 10032.76 7939.09 13567.71 13163.31 14485 13324 33202.06 25765.06 13490.1 9881.31 8262.94 9957.42 9957.42 17994.5 50531 37467 76393 49665 62410 43157 40727 37287 68801 62940 54441 91708 193016 73273 alternate_total_cost_of_re_fuel biomass_moisture_content comments Hatchery using little water Unit 2 runner replaced Low water in reservoir Date: period from 1-1-16 to 7-31-16, no unscheduled maintenance scheduled regular maint included, filters, brushes & inspections During times of low system load one unit at time is off line PLC problem on unit 2 16 hrs downtime During the time period of 1-1-17 to 9-30-17 no unscheduled down time, unit downtime was scheduled to perform maintenance Stetson contribution based on actual cooper lake generation and assumption of contribution of 6020 mwh annually Green Lake Hydro and Jarvis Diesel provide Sitka Generation in addition to Blue Lake Hydro electric_efficiency_after_re_integration month 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 10 11 12 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 nonscheduled_maintenance_hours notes parasitic_load 6731 16526 11997 8902 7329 4818 5771 5400 5168 6580 4726 5243 5088 5846 5042 5126 7037 5929 5785 5346 5406 4237 5083 4890 4543 5068 7067 7857 8939 7631 10087 9718 9210 6650 5904 5849 4662 6097 7769 9417 29042 30830 27448 22693 18886 15346 14815 20189 27231 23211 24552 99800 101100 94600 100300 71200 60400 45800 50600 67300 697400 101300 93500 92900 110000 84400 75100 65000 59800 51300 61700 54700 71800 95400 104800 115100 103600 103400 78700 87500 61000 51400 54700 62200 79900 98000 86900 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 125 123 114 222 87 54 54 40 50 95 116 0 0 0 88000 84000 86000 70000 63000 55000 54000 54000 56000 59000 64000 67000 64000 62000 62000 57000 56000 50000 52000 50000 67000 69000 60000 69000 86 87 86 61 58 58 49 48 55 75 78 74 scheduled_maintenance_hours year 2014 2014 2014 2014 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2014 2014 2014 2014 2014 2014 2014 2014 2014 2014 2014 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2014 2014 2014 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 project__id 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 504 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 848 project__electric_efficiency_prior_to_re_integration 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 project__electric_generation_fuel_displaced True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True project__goal_net_heat_delivered project__goal_net_re_electric_generation 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 16000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 130000000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 48500000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 32000000 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-135.17 project__master_project_code 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10040 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10118 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10315 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 10416 project__project_expected_completion_date 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41609 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 41639 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 42217 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 41994 project__project_full_commission_date 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 42005 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 41993 project__project_notes The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft The Stetson Creek Diversion Project comprises the construction of facilities and structures to divert water from Stetson Creek, convey it approximately 2 miles to Cooper Lake, and allow controlled releases of water from Cooper Lake into Cooper Creek as an expansion of existing hydropower facilities owned and operated by Chugach Electric Association. The diversion is the result of a licensing mitigation strategy that involves removing cold water from Cooper Creek (the Stetson Creek diversion) and discharge a designated amount of warmer water from the Cooper Lake reservoir to Cooper Creek (the siphon construction) in an effort to restore anadromous salmon presence in Cooper Creek. Prior to the construction of the Stetson diversion, Cooper Lake operations diverted all flow from Cooper Lake through the tunnel/penstock to the powerhouse, where it is discharged into Kenai Lake. The 4.8-mile-long Cooper Creek bypassed reach below the Cooper Lake dam received no flow from Cooper Lake; there was no existing minimum flow requirement for Cooper Creek and no outlet structure to provide such flows. The original project had an average annual generation of about 48,500 megawatt-hours (MWh) and an average outflow through the powerhouse of about 100 cubic feet per second (cfs), which is equivalent to 73,000 acre-feet/year. Powerhouse discharge ranged from 0 to 380 cfs into Kenai Lake. The Stetson diversion project consisted of the following main elements: • Construction of a new Diversion Dam on Stetson Creek, • Construction of a 2.2-mile-long diversion pipeline from the new Diversion Dam on Stetson Creek to Cooper Lake, and • Construction of Siphon Outlet Facilities in the existing Cooper Lake Dam spillway alignment to allow controlled releases of water from Cooper Lake into Cooper Creek. The Stetson diversion’s impact on operations is summarized below: • Maximum Diversion from Stetson Creek – 110 cubic feet per second (cfs) • Minimum Instream Flow (MIF) Remaining in Stetson Creek during Diversion – None specified • Minimum Annual Volume Diverted from Stetson Creek to Cooper Lake – 18,285 ac-ft+/- • Total Volume Released from Cooper Lake into Cooper Creek per year – 10,256 ac-ft • Expected net Generation Increase from Stetson Creek Diversion Flow – 8,029 ac-ft project__project_operation_start_date 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41932 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 41640 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 42233 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 41957 project__electric_generation_fuel_displaced_type__id 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 project__electric_generation_fuel_displaced_type__abbreviation DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO DFO project__electric_generation_fuel_displaced_type__conversion_factor_mmbtu 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 1.021 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 0.13869 project__electric_generation_fuel_displaced_type__emission_factor 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 53.06 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 73.15 project__electric_generation_fuel_displaced_type__name Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil Distillate Fuel Oil project__electric_generation_fuel_displaced_type__physical_units Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF MCF Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons Gallons project__heat_fuel_displaced_type__id project__heat_fuel_displaced_type__abbreviation project__heat_fuel_displaced_type__conversion_factor_mmbtu project__heat_fuel_displaced_type__emission_factor project__heat_fuel_displaced_type__name project__heat_fuel_displaced_type__physical_units project__re_utility__id 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 54 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 27 project__re_utility__certificate True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True True project__re_utility__eia_operator_id 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10210 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 10433 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 3522 project__re_utility__name Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Ketchikan Public Utilities Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Kodiak Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc Chugach Electric Assn Inc project__re_utility__pce_id project__re_utility__regulatory_status__id 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 project__re_utility__regulatory_status__name Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Not regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated Regulated project__re_utility__utility_type__id 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 project__re_utility__utility_type__name Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Public Electric Utility Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op Electric Co-op project__technology_type__id 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 project__technology_type__name HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO HYDRO