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AK Intertie RIRP study 2010
DRAFT -For Review only @rectic Power Sysens Al "hxt- ¢\Consulting Engineers me)+. &*-SYSTEMS -*- Alaska Energy Authority September 4,2012 813 Northern Lights Blvd Anchorage,Alaska 99503 Att:Mr.James Strandberg,P.E. Subject:Railbelt Project List/Preliminary Benefits Analysis Dear Mr.Strandberg: Electric Power Systems,Inc.has developed a list of backbone transmission projects for the Railbelt electrical system.The projects cover the entire length of the Railbelt from Homer to Fairbanks,Alaska. Though additional projects may be identified with further analysis,the projects included in this list are considered the core projects required to provide a backbone transmission system for the entire Railbelt region. Project Summaries Many of the projects are inter-related,supporting each other and reducing the cost of each project if compared to if they were evaluated individually.Consequently,the removal of any single project from the list may have cost or reliability consequences to the remaining projects above the stated cost of the individual project as part of the group.The projects are listed and described below,however the order does not signify an order of importance or priority. Project Name:Beluga -Bernice Lake HVDC Intertie Project Description: This project includes the construction of a 100 MW HVDC intertie between the Beluga power plant in Southcentral Alaska and the Bernice Lake Power Plant on the Kenai Peninsula.The interconnecting power line would consist of two undersea cables,each rated for 100 MW transfer capacity.The cables are approximately 36 miles in length and are estimated to be 300 kcm copper conductors rated at 80 kV DC.The converters are mono-pole HVDC converters with a transfer capacity of 100 MW.The actual voltage and submarine cable ratings will require optimization to provide the most economic selection for the project. Project Benefits: The installation of the HVDC Beluga-Bernice Lake tie is a key component in the removal of restrictions on the operation of Bradley Lake.The project allows the Kenai export to exceed 125 MW,allowing Bradley and Cooper Lake to operate unconstrained to their full capacity.The project will also allow excess thermal energy from Kenai generation to be supplied to the Anchorage/Mat-Su and Fairbanks areas without restricting the use of Kenai hydro resources.The project reduces the losses associated with hydro energy from an estimated 8-10%of the plant's output to less than 3%.The project will allow Bradley and Cooper Lake units to be optimally dispatched with future large hydro projects,resulting in an optimization of hydro resources on the entire Railbelt. AEA Public Benefit Backbone Project Cost and Benefit List Project Cost: The cost of the project is estimated at $165-$206M.The large price variation is due to the pricing variability in HVDC converters and submarine cables.A cable/HVDC converter optimization study could help narrow the cost band and result in a lower overall cost. Project Name:Bradley Lake -Soldotna 115 kV Transmission Line Project Description: This project includes the construction of a new 68 mile long,115 kV transmission line from the Bradley Lake Power plant to a new substation near HEA's existing Soldotna substation.The transmission line includes modifications to the existing GIS switchgear and 0.5 miles of 115 kV solid-dielectric cable at the Bradley Lake power plant.The northern end of the line would terminate in a new 115 kV substation connected to the existing HEA substation through the existing AEA SVC bay.The line would utilize the same construction configuration and conductor size as the existing Bradley -Soldotna transmission line. Project Benefits: The construction of the new 115 kV transmission line is a key element in the reduction of losses and stability for time periods of high Bradley Lake output.The new line will allow unconstrained operation of Bradley Lake following the construction of the HVDC tie and also allows thermal generation to be utilized to export power to northern utilities without impacting the Kenai hydro resources. Project Cost: The cost of the project is estimated at $67.5M.This cost includes the purchase of additional land at Soldotna for the substations,reconfiguration of the existing 115 kV Soldotna Substation SVC take-off, underground cable at Bradley,GIS modifications at Bradley and the overhead transmission line. Project Name:University -Dave's Creek 230 kV Transmission Line Conversion Project Description: This project includes the conversion of 77 miles of existing 115 kV transmission line from 115 kV to 230 kV from Chugach's Dave's Creek Substation on the Kenai Peninsula to Chugach's University Substation in Anchorage.The project requires two separate phases,the conversion of the line to 230 kV followed by the conversion of the substations to 230 kV.The line conversion would include rebuilding the line across the avalanche areas along the existing route.This conversion would include the installation of deflection structuresand the installation of more avalanche resistant structures.The line would be placed along the existing line's route. Project Benefits: The conversion of the existing 115 kV transmission line to 230 kV is a key element in the reduction of losses and improved stability for the transmission system.The converted 230 kV line will allow unconstrained operation of Bradley Lake following the construction of the HVDC tie.The project also allows thermal generation to be utilized to export power to northern utilities without impacting the Kenai hydro resources.When the HVDC line is out of service,the upgrade to 230 kV will allow the Kenai hydro resources to be used to serve the Anchorage/Mat-Su and Fairbanks areas with significantly reduced losses as well as being able to provide spinning reserve to the Railbelt system.Even prior to converting the line to 230 kV operation,reconstructing the existing line to 230 kV standards will decrease the system losses and improve the reliability of the line while being operated at 115 kV. Project Cost: The cost of the project is estimated at $56.9M.This cost includes the conversion of the existing line from 115 kV to 230 kV,but does not include the cost of adding compensation required to operate the line at 230 kV or the conversion of the existing stations to 230 kV operation. August 15,2012 Page 2 pee eseéRyConsultingEngnears AEA Public Benefit Backbone Project Cost and Benefit List Project Name:University -Dave's Creek 230 kV Substations &Compensation Project Description: This project includes the installation of reactive compensation at Dave's Creek station and the conversion of substations at Dave's Creek,Hope,Summit Lake,Portage,Girdwood and Indian stations to 230 kV. The project also includes the completion of the 230 kV bus at Chugach's University substation.The project also includes the installation of sectionalizing switches at each of the stations to allow remote sectionalizing of the transmission line. Project Benefits: The conversion of the existing 115 kV transmission line to 230 kV is a key element in the reduction of losses and improved stability for the transmission system.Following the conversion of the transmission line to 230 kV,this project will allow for the operation of the line and all its substations at 230 kV.The converted 230 kV line will allow unconstrained operation of Bradley Lake following the construction of the HVDC tie and also allows thermal generation to be utilized to export power to northern utilities without impacting the Kenai hydro resources.When the HVDC line is out of service,the 230 kV conversion will allow the Kenai hydro resources to be used to serve the Anchorage/Mat-Su and Fairbanks areas with significantly reduced losses as well as being able to provide spinning reserve to the Railbelt system. Project Cost: The cost of the project is estimated at $32.2M.This cost includes the installation of.additional compensation at Dave's Creek and the conversion of each of the transmission stations between Dave's Creek and University to 230 kV. Project Name:25 MW BESS-Anchorage Area Project Description: This project includes the installation of a 25 MW/14 MWh Battery Energy Storage System (BESS)in the Anchorage area.The exact characteristics of the BESS technology should be evaluated in the design and procurement of the BESS. Project Benefits: Although physically located in the Anchorage area,the BESS will provide system support for the 230 kV, 138 kV and 115 kV systems located in the Anchorage and Mat-Su areas.In addition to providing local transmission support,the BESS will provide regulation support and frequency support for the entire Railbelt.The BESS will be capable of providing regulation for small-medium variable generation projects such as wind,solar,run-of-the-river hydro etc as well as providing response to the system during transient events.As the Railbelt moves towards smaller,light inertia units,the number of underfrequency load shedding events may increase as the number of equal size units increases in the new light inertia system. The BESS will also prevent the load shed for this typical loss of generation condition.The BESS also allows the Beluga-Bernice Lake HVDC line to be sized smaller than would otherwise be required by replacing energy in the Anchorage system for a short period of time following the loss of either of the transmission lines between Anchorage and Kenai. Project Cost: The cost of the project is estimated at $30.2M.This cost includes the BESS ($26.7M)step-up transformer,breakers and substation work ($3.5M). August 15,2012 Page 3 AEA Public Benefit Backbone Project Cost and Benefit List Project Name:Flexible Gas Storage -Anchorage Area Project Description: This project includes the installation of a 1.91 MCF (262 MWh)gas storage facility at an Anchorage/Mat- Su area power plant.The gas storage includes storage tanks for compressed natural gas,compressor, compressor building and delivery system. Project Benefits: The flexible gas storage system will allow the in-ground storage tanks to be fully utilized to respond to changes in variable generation or generation contingencies without relying on the gas delivery system. This will allow the thermal units to respond to changes in load and increased generation requirements without stressing the gas delivery system and ensuring the gas delivery system can supply the required demand of the system.The flexible gas storage will allow the thermal generation system in Anchorage/Mat-Su to respond to the loss of one of the Anchorage -Kenai ties to provide thermal generation to replace the lost energy if one line is forced out of service.The gas storage will allow thermal generation to respond to changes in renewable generation,eliminating the requirement for hydro generation to be on-line 24 hours per day to regulate against the renewable energy generation.This allows the hydro to be used primarily to reduce the cost of generation in the most cost effective manner for the system. Project Cost: The cost of the project is estimated at $18.2M.This cost includes the gas storage system,compressor building,and associated pipes at the power plant. Project Name:Fossil Creek Substation Project Description: This project includes the construction of the 115 kV Fossil Creek substation.The Fossil Creek substation is located near the existing Briggs Tap on the Eklutna --AML&P transmission line.The projects includes the construction of a 115 kV substation to interconnect the Eklutna Express circuit,the Eklutna local circuit,and the AML&P express circuit with provisions for future 230/115 kV transformers and Raptor substation interconnections. Project Benefits: Construction of the Fossil Creek 115 kV substation (in conjunction with the Eklutna substation project below)will allow the existing AML&P -Eklutna transmission line to be sectionalized between Eklutna and Anchorage.Without sectionalizing,outages to the existing line result in a loss of electrical service to the communities of Eagle River,Chugiak and Eklutna and the loss of power from the Eklutna generation plant in to the Anchorage area.A new express transmission line between Fossil Creek and Eklutna stations will provide power to the Anchorage area during outages to the local transmission line.The substation will allow the local transmission line to be sectionalized and the loads served from either end of the looped transmission system,preventing a complete loss of power to the residents for any single fault on the transmission system.The substation will allow the express circuit to be energized,providing a reliable source of black start power for the AML&P system,allowing AML&P to utilize the plant for starting its electrical system in the event of a system-wide blackout. Project Cost: The cost of the project is estimated at $8.25M.This cost includes the substation development,equipment, communications and construction. August 15,2012 Page 4 or Cusine iste AEA Public Benefit Backbone Project Cost and Benefit List Project Name:Eklutna Substation Project Description: This project includes the construction of the 115 kV substation at the Eklutna power plant.The Eklutna Substation is currently located on the roof of the Eklutna Power Plant.The new substation will be relocated to adjacent to the Eklutna power plant.The project includes the construction of a 115 kV substation to interconnect the Eklutna Express circuit,the Eklutna local circuit,and the 115 kV Palmer circuit with provisions for future 230/115 kV transformers and Raptor substation interconnections. Project Benefits: Construction of the Eklutna 115 kV substation (in conjunction with the Fossil Creek substation project above)will allow the existing AML&P -Eklutna transmission line to be sectionalized between Eklutna and Anchorage.Without sectionalizing,outages to the existing line result in a loss of electrical service to the communities of Eagle River,Chugiak and Eklutna and the loss of power from the Eklutna generation plant into the Anchorage area.A new express transmission line between Fossil Creek and Eklutna stations will provide power to the Anchorage area during outages to the local transmission line.The substation will allow the local transmission line to be sectionalized and allow the loads to be served from either end of the looped transmission system,thereby preventing a complete loss of power to the residents for any single fault on the transmission system.The substation will allow the express circuit provide a reliable source of black start power for the AML&P system,allowing AML&P to utilize the plant for starting its electrical system in the event of a system-wide blackout.The new substation will replace oil-filled breakers which have reached the end of their useful life.The project also includes the installation of communications required to bring the 115 kV line protection up to both the utility standards and the stability requirements of the Railbeit. Project Cost: The cost of the project is estimated at $6.15M.This cost includes the substation development,equipment, communications and construction. Project Name:Lake Lorraine Substation Project Description: This project includes the construction of the 230 kV substation near the confluence of Chugach's 230 kV West Terminal and its Teeland Transmission lines.The substation would provide a termination for the Lorraine -Douglas transmission line(s)and be constructed for six line terminals (2-Pt Mackenzie,West Terminal,Teeland,2-Douglas)with provisions for a future 230/115 kV transformer.The substation includes an -85/+25 MVAr SVC at the station to control voltages on the 230 kV system during periods of low and high power transfer. Project Benefits: Construction of the Lake Lorraine 230 kV Station and the subsequent transmission line(s)to Douglas Station eliminate the largest transmission contingency in the Railbelt,the single circuit Pt.MacKenzie- Teeland transmission line that serves MEA and GVEA._The station will eliminate the single contingency service to Teeland station from the 230 kV system and will eliminate over 50 miles of single contingency service to Anchorage-Fairbanks Intertie.The station will allow for completion of the Anchorage - Fairbanks Intertie,removing its reliance on a 115 kV constructed portion of the line from Douglas to Teeland that has been the source of many outages.The station will serve as a key terminal and delivery point for the Railbelt,increasing the reliability and power transfer capability between Anchorage and Fairbanks and between the Mat-Su Valley and Anchorage.Following the completion of new generation in Anchorage,Kenai and the Mat-Su Valley,additional reactive support is required to provide voltage control on the 230 kV transmission system.This reactive support will be provided by the SVC included in the station. August 15,2012 Page 5 seesConsultingEngiwreers AEA Public Benefit Backbone Project Cost and Benefit List Project Cost: The cost of the project is estimated at $84M ($12.5M for the station,$71.5M for the SVC).This cost includes the substation development,equipment,communications and construction. Project Name:Douglas Substation Expansion Project Description: This project includes the construction of the 230 kV/138 kV substation at the existing Douglas substation near Willow,Alaska.The substation will serve as the voltage conversion for the 138 kV Anchorage- Fairbanks Intertie and will include two 230 kV /138 kV substation transformers.The station will be constructed for two 230 kV /138 kV power transformers,two 138 kV transmission lines (Anchorage- Fairbanks),one 138 kV /24.9 kV power transformer and one 138 kV line (Teeland). Project Benefits: Construction of the Douglas 230 kV Station and the subsequent transmission line(s)to Lorraine Station and Gold Creek/Healy stations eliminates the largest transmission contingencies in the Railbelt,the single circuit Pt.MacKenzie -Teeland transmission line that serves MEA and GVEA,and the single transmission circuit that delivers power between Anchorage and Fairbanks.The second line to Healy via Gold Creek station will allow firm power transfers between Anchorage/Kenai and Fairbanks.The station will allow for completion of the Anchorage -Fairbanks Intertie,removing its reliance on a 115 kV constructed portion of the line from Douglas to Teeland that has been the source of many outages.The station will serve as a key terminal and delivery point for the Railbelt,increasing the reliability and power transfer capability between Anchorage and Fairbanks and between the Mat-Su Valley and Anchorage. Project Cost: The cost of the project is estimated at $16.5M.This cost includes the substation development,equipment, communications and construction. Project Name:Gold Creek Station Project Description: This project includes the construction of a 230 kV (operated at 138 kV)substation near Gold Creek on the Alaska Intertie.The station will provide compensation and sectionalizing support for the Anchorage - Healy transmission lines and will include 4 line terminals and two reactors. Project Benefits: Construction of the Gold Creek 230 kV (operated at 138 kV)Station will significantly reduce the reactive compensation required to operate the transmission system from Anchorage -Fairbanks.Location of the line reactors near the %point of the line will allow the net reactive compensation at Lorraine to be reduced by over 80 MVA ($56M).The station is also strategically located to provide improved sectionalizing between the Douglas and Healy stations,to provide improved reliability,and to provide power transfer following the outage to any single line section connected to Gold Creek. Project Cost: The cost of the project is estimated at $14.5M.This cost includes the substation development,equipment, communications and construction. Project Name:Healy Station Project Description: This project includes the construction of a 230 kV (operated at 138 kV)substation near Healy,Alaska on the Alaska Intertie.The station will allow the termination of an additional line from Gold Creek into the Healy Plant.The station will be constructed for future operation at 230 kV should a future large hydro August 15,2012 Page 6 AEA Public Benefit Backbone Project Cost and Benefit List project come on-line.The station will include terminations for two 230 kV (operated at 138 kV)lines to Gold Creek,lines to GVEA's Wilson Substation and GVEA's Gold Hill Substation,lines to existing Healy plant and a SVC. Project Benefits: Construction of the Healy 230 kV station will allow the second Anchorage -Healy transmission line to be interconnected into the GVEA transmission system and the Railbelt backbone.The station will provide the ability to receive firm capacity and energy over the intertie,allowing economic operation of the power system.The firm transmission of power will allow both Southern and Northern utilities to plan on the intertie for capacity reserves and to provide these reserves during times of natural disasters,regional fuel shortages or other issues which require power transfer between geographically distinct regions. Project Cost: The cost of the project is estimated at $16.5M.This cost includes the substation development,equipment, communications and construction. Project Name:Lorraine -Douglas Transmission Line Project Description: This project includes the construction of a 42-mile,230 kV double circuit transmission line from Lake Lorraine substation to Douglas Substation.The line will be constructed as a single tower,double-circuit transmission line utilizing construction similar to the Eklutna-Fossil Creek line. Project Benefits: The transmission lines complete the Anchorage -Fairbanks Intertie started in 1984 and provides for transfer of power and the sharing of reserve capacity between the Kenai/Anchorage/Mat-Su and Fairbanks areas.The firm transmission of power will allow both Southern and Northern utilities to plan on the intertie for capacity reserves and to provide these reserves during times of natural disasters,regional fuel shortages or other issues which require power transfer between geographically distinct regions. Project Cost: The cost of the project is estimated at $50.5M.This cost includes the line design,permitting,equipment and construction of the transmission line. Project Name:Douglas -Healy Transmission Line Project Description: This project includes the construction of a 171-mile,230 kV (operated at 138 kV)transmission line from Douglas substation to Healy substation.The line will be constructed as a single-circuit transmission line utilizing construction similar to the existing Anchorage-Fairbanks Intertie at 230 kV.The line will utilize bundled,954 conductor to minimize losses.The line will terminate at Douglas,Gold Creek and Healy stations. Project Benefits: The transmission line provides both transfer of power and the sharing of reserve capacity between the Kenai/Anchorage/Mat-Su and Fairbanks areas.The firm transmission of power will allow both Southern and Northern utilities to plan on the intertie for capacity reserves and to provide these reserves during times of natural disasters,regional fuel shortages or other issues which require power transfer between geographically distinct regions. At current oil prices in the Fairbanks area and current gas prices in the Southcentral area,the potential benefits for the Fairbanks area consumers for an increase in firm capacity of 25 MW of firm capacity is $26.6M/year.For an increases of 50 MW (the planned rating of the line)and a 90%utilization factor the annual benefits are $47.95M/year. August 15,2012 Page 7 AEA Public Benefit Backbone Project Cost and Benefit List Project Cost: The cost of the project is estimated at $204.0M.This cost includes the line design,permitting,equipment and construction of the transmission line. Project Name:Communication Infrastructure Project Description: This project includes the development and installation of a communication infrastructure between Teeland, Lorraine,Douglas,Gold Creek and Healy stations.The communications will be used for high-speed protective relaying,communications between control areas and control and monitoring of the substation equipment. Project Benefits: The communication system is required to provide high-speed protective relaying between each of the stations,allowing for the firm transfer of power between areas and increasing the stability limit for power transfer between the northern and southern Railbelt.Absent communications,the power transfer and stability limit are reduced and the ability operate and control the system in reliable manner to maximize the efficiency of the power system is constrained. Project Cost: The cost of the project is estimated at $15.0M.This cost includes the line design,permitting,equipment and construction of the communication system. Benefit Analysis This report is intended to provide a high-level benefit analysis of the Railbelt projects recommended for construction prior to 2023.Similar to the project costs,the benefit analysis is difficult to evaluate on an individual project basis.Most benefits are derived from the combined effect of the projects as opposed to the impact of a singular project.Many benefits,such as the ability to share capacity and energy from the northern to the southern portions of the Railbelt grid are beyond the scope of this project. The benefits identified as a result of this project are as follows: 1.Energy Loss Analysis In the existing system,losses from the Bradley Lake project are minimized by the effective displacement of the Bradley energy by the Beluga power plant located in the central Railbelt area.This has effectively delivered the Bradley capacity and energy to the Railbelt with minimal losses by minimizing the power transfer over the Anchorage-Kenai Intertie.Following the installation of Kenai area generation,all of Bradley's energy will be delivered to the central and northern utilities at Chugach's University substation through the 115 kV Kenai transmission line.It will not be displaced by the Beluga or other northern generation resources. In 2008,Beluga generation displaced approximately 193,973 MWh from the Bradley project.Following the addition of Kenai area generation,this energy will be required to flow from the Bradley project through the Kenai-Anchorage Intertie to the central and northern utilities.The power delivered to the central and northern Railbelt utilities will be reduced by the increased losses of the Kenai transmission system. The losses for Bradley Lake energy are estimated to be replaced with marginal cost thermal generation. The estimated amount of lost annual energy is 34,065 MWh.Assuming a replacement cost of $100/MWh, the annual cost is estimated to be $3,406,000/year. The losses for Cooper Lake are anticipated to increase 9%over historical values for the Chugach system. These losses are estimated at 2,994 MWh with a value of $299,400/year. August 15,2012 Page 8 oO Cute asters AEA Public Benefit Backbone Project Cost and Benefit List 2.Stranded Capacity Following the addition of Kenai area generation and the cessation of Beluga displacement capability,the resulting transmission restrictions will result in the loss of Bradley capacity for the central and northern utilities. The stranded capacity is estimated to be 31 MW to the northern utilities with a NPV of $136,300,000 in 2012 dollars for a 30-year life. 3.Excess Energy Periodically,Bradley has excess energy that must be used in order to avoid losing energy over the spillway.In these conditions,Bradley has historically been operated between 90 MW and 115 MW and each participant is allocated a proportional share of the excess energy. Plant dispatch records from 2002-2010 were correlated with lake level to determine the amount of energy the participants have been forced to take in order to avoid losing energy over the spillway.There was an expected wide variation in energy levels,with the high value in 2002 of 61,118 MWh to 0 MWh in 2004, 2005,2007,2008,and 2010.The average for the nine years records available was 11,462 MWh. The average value of excess energy for the eight years evaluated was $1,261 ,000/year. 4.Hydro-Thermal Coordination Hydro-thermal coordination refers to the ability of hydro energy to replace high-cost thermal energy throughout the course of a day or year.In the past,hydro-thermal coordination has provided millions of dollars in benefits every year to the Railbelt utilities.However,the installation of smaller,more efficient thermal generation will decrease the benefit that the utilities have historically experienced. The loss of hydro-thermal coordination will result in an increased cost to the utilities of $1,100,000 based on preliminary estimates. 5.Reservoir Management Historically,the water management has been performed by projecting energy usage by month to determine the expected reservoir level.During high inflow months,the project participants have been forced to take their fully allocated share in order to avoid loss of energy over the spillway,even though this energy is not deemed excess or above average energy.The restrictions on the project output will eliminate the ability of utilities to declare pending spill conditions and will increase the chance of energy spill during high inflow periods. During normal water years,project participants will be able to receive all of their Bradley energy,however during certain months the required take will approach an 80%load factor.Historically,Bradley's highest monthly load factor was less than 50%,since Bradley was regularly dispatched to its full load during peak times but was often not utilized for energy production in off-peak periods. Due to the energy withdrawals that are required to manage the reservoir water levels,any single utility's ability to store water in the reservoir from one water year to the next will be significantly diminished following the termination of the Beluga displacement provisions.The utilities'practice of storing water in the reservoir in the fall to be utilized in the winter months may put additional water at risk as their ability to draw the reservoir down during heavy fall inflows to keep it below spill level may be reduced. However,the capacity restriction on Bradley may increase the risk of spilled energy over previous years. Managing the reservoir level of Bradley to a 10'lower level will reduce the energy output of Bradley by approximately 1%/year. August 15,2012 Page 9 AEA Public Benefit Backbone Project Cost and Benefit List If the reservoir is lowered by 10'on average in order to avoid spilled energy,the available energy from Bradley Lake will be reduced by an average of $433,000/year. 6.Spinning Reserve Historically,spinning reserve located on the Kenai was not restricted by the limitation on the Anchorage- Kenai Intertie.This was partly due to a single entity operating the generation located in the both the Kenai and Anchorage areas and partly due to operating limits of the generation.Historically,most of the spinning reserve on the Kenai was located at Bradley Lake,with little spinning reserve from thermal generation located on the Kenai.However,starting in 2015,Kenai area spinning reserve will be located at both Bradley Lake and thermal resources on the Kenai as a spinning reserve obligation is undertaken by AEEC for its Kenai area resources. Historically,the Kenai-Anchorage transmission line's ability to provide the transmission capacity for the Kenai spinning reserve was met with the operating practices and realities of the generation and transmission systems.In order to provide 75 MW of export,sufficient generation capacity needed to be operating to serve the native Kenai area load plus provide 75 MW of export,such that there was little capacity left for spinning reserve.The 25-27 MW of capacity remaining on the transmission line above 75 MW essentially matched the spinning reserve capacity of the remaining resources. However,in 2015,AEEC will incur a spinning reserve obligation of approximately 13 MW on the Kenai that will add to the capacity requirement for the Kenai-Anchorage transmission line.The transfer limit which utilizes the Anchorage-Kenai line for the transfer of power during both steady-state and transient events will increase from approximately 100 MW to 113 MW.This leaves the current tie approximately 13 MW short of capacity for central or northern area generation deficiencies. The increased cost of spinning reserve to the Northern utilities is estimated at $6,000,000/year. 7.Capacity and Energy Sales The existing transmission line precludes the possibility of economic or firm power sales between Kenai thermal generation and northern utilities.The installation of new,efficient generation on the Kenai as well as the older units that can be used as reserves could provide a benefit to both the Kenai and northern utilities systems.In addition to these units,the construction of a second transmission line to Fairbanks will provide GVEA access to the same gas costs and energy production rates as afforded the southern Railbelt utilities.The available generation capacity in the Southcentral area could provide great benefit to reducing the energy costs of GVEA consumers. Assuming that 100 MW of this firm capability is used with a 100%load factor results in an estimated firm power savings of over $26.6M/year at current pricing levels.Using the intertie to its full capability results in an annual savings of over $47.95M/year.The 30-yr NPV of the 100 MW transfer is $351.6M and the 50 yr NPV of the 125 MW transfer is $633M.The 50-yr NPV of the 100 MW transfer is $393M and the 50 yr NPV of the 125 MW transfer is $708M. This benefit does not include the capacity deferral benefit that may be possible to GVEA consumers by avoiding the construction of additional capacity through the purchase of firm capacity and energy from existing capacity in Soutchentral utilities. 8.Reduced Construction Costs The existing transmission system between Anchorage and Kenai consists of a single circuit 115 kV transmission line between Chugach's University station and Homer's Soldotna Station.The portion of the line between University and Dave's Creek will require considerable re-construction over the next several years.Anew HVDC transmission line between Beluga and Bernice Lake will allow the construction to be August 15,2012 Page 10 Ayers&2)Consulting Enginesrs AEA Public Benefit Backbone Project Cost and Benefit List completed in a more economical fashion.The line can be de-energized without an interruption of Bradley and Cooper Lake power and construction can be completed on the de-energized line in longer stretches, significantly reducing the costs of the reconstruction. The cost of re-building the single University-Dave's Creek transmission line without an HVDC Beluga- Bernice Lake alternative path is estimated to increase the construction 30%above the alternative,or approximately $19,000,000.This cost does not include the increased cost of generation during the reconstruction due to the line outage. 9.Reduced Battery Costs In the existing transmission configuration,the loss of the single Anchorage-Kenai transmission line represents the single largest contingency to the northern and central Railbelt utilities.The contingency must be countered by either the construction of a BESS in the central area or additional spinning reserve being carried in the northern areas.Unconstraining Kenai generation by the construction of a Beluga - Bernice Lake HVDC line reduces this contingency considerably and will reduce the size and costs of a BESS and eliminates the need for additional spinning reserves in the northern area. The HVDC Beluga -Bernice Lake transmission line is estimated to reduce the required size of the Anchorage area BESS by 50 MW,or approximately $65,000,000. 10.Reduced Flexible Gas Storage Costs In the existing transmission configuration,the loss of the single Anchorage-Kenai transmission line represents the single largest contingency to the northern and central Railbelt utilities.The contingency must be countered by either the construction of a BESS in the central area or additional spinning reserve being carried in the northern areas.Although the BESS can supply energy in the short-term,longer term energy must be supplied through the thermal units following the loss of the single Kenai transmission line. Unconstraining Kenai generation by the construction of a Beluga -BLPP HVDC line reduces this contingency considerably.The HVDC line will reduce the size and costs of a FGS,and eliminate the need for additional spinning reserves in the northern area. The Beluga-Bernice Lake transmission line is estimated to reduce the required size of the Anchorage area FGS by 50 MW,or approximately $59,000,000. Summary Table -Projects Item Description Cost Notes Bernice Lake-Beluga HVDC 100 MW HVDC Intertie $165-$206M Bradley-Soldotna 115 kV Line New line $67.5M University-Daves Creek 230 kV__|Reconstruct existing line $56.9M University-Daves Substations Convert line for 230 kV operation |$32.2M 25 MW/14 MWh BESS Anchorage area battery $30.2M 262 MWh Flexible Gas Storage |Gas storage at local plant $18.2M Fossil Creek Station 115 kV substation $8.25M Eklutna Station 115 kV substation $6.15M Lake Lorraine Substation 230 kV substation $84M Includes SVC Douglas Substation 230/138 kV station $16.5M Gold Creek station 230 kV station/operated at 138 kV |$14.5M Healy station New station $16.5M Lorraine-Douglas Line Double circuit 230 kV line $50.5M Douglas -Healy line 230 kV line operated at 138 kV $204M Communication $15.0M August15,2012 Page11 (pers PS AEA Public Benefit Backbone Project Cost and Benefit List Summary Table -Benefits Item Description Benefit Notes 30 yr NPV |50 Yr NPV Energy Losses Decreased losses $52.4M $62.2M Excess Energy Increase energy for high h20 |$19.4M $23.1M Hydro-thermal Thermal/hydro coordination $16.9M $20.1M Reservoir Mgmt Decreased head level $6.7M $7.9M Spinning Reserve _|Increased reserves in north $92.2M $109.6M Firm Power Sales |GVEA Energy savings $351.6M $633.0M Does not include capacity deferral Reduced Construction savings -Anc-|$19.0M $19.0 M Construction cost __|Kenai lineReducedBESS75MWto25MW BESS size __|$65M $65M FGS reduction 75MW to 25 MW FGS size $59M $59M Project Cash Flow Requirements Item Year 1 Year 2 Year 3 Year 4 Year 5 Year 6-8 Bernice Lake-Beluga HVDC $7.0M $65M $65 $30-$69M Bradley-Soldotna 115 kV Line |$1.0M $1.5M $32M $33M University-Daves Creek 230 |$1.5M $15M $17M $14M $9.4M kV University-Daves Substations |$1.6M $23M $7.6 25 MW/14 MWh BESS $2.6M $9M $18.6M 262 MWh Flexible Gas |$1.5M $16.7M Storage Fossil Creek Station $2.5M $5.75M Eklutna Station $2.0M $4.15M Lake Lorraine Substation $1.0M $35M $48M Includes SVC Douglas Substation $3.5M $13.0M Gold Creek station $3.5M $11.0M Healy station $1.0M $4.5M $11.0M Lorraine-Douglas Line $1.0M $2.0M $30M $17.5M Douglas -Healy line $1.0M $3.0M $2.0M $15M $36M $49M/year Communication $1.0M $5.0M $4.0M $5.0M August 15,2012 Page 12 Karl Reiche From:Kirk H.Warren Sent:Friday,September 28,2012 1:19 PM To:Karl Reiche Subject:FW:ARCTEC List Attachments:Unconstraining Bradley Priority List ARCTEC.xIsx Hi Karl,attached is the ARCTEC list of requested State Appropriations for FY14.The last column is a prioritized list of Projects to "Unconstrain Bradley”and are the only Projects that Sara is going to consider requesting monies for in the Governor's Budget (she may reduce the list as well based on her budget meetings today). |will bring down a copy of Dave Burlingame's description of the Projects listed in the attachment. Kirk Kirk H.Warren,P.E. Alaska Energy Authority Project Manager,Infrastructure (907)771-3072 Direct (907)240-8663 Cell "Lead by Example” From:Kirk H.Warren Sent:Tuesday,September 25,2012 2:19 PM To:Amy Adler Cc:Gene Therriault;Sara Fisher-Goad Subject:ARCTEC List Hi Amy,see attached.If you have a moment!will come up and discuss? Kirk Kirk H.Warren,P.E. Alaska Energy Authority Project Manager,Infrastructure (907)771-3072 Direct (907)240-8663 Cell Geax)ENERGY AUTHORITY "Lead by Example” ARCTEC Project Cash Flow Requirements ($millions)Unconstraining Bradley Priority Ranking Fiscal Year 2014 2015 -2016 2017 2018 Bernice Lake-Beluga HVDC 7.0 65.0 65.0 50.0 2.0 Bradley-Soldotna 115 kv Line 1.0 1.5 32.0 33.0 2.5 University-Daves Creek 230kV 1.5 15.0 17.0 14.0 9.4 4.0 University-Daves Substations 1.6 23.0 7.6 5.0 25 MW/14 MWh BESS 2.6 "9.0 18.6 3.0 262 MWh Flexible Gas Storage 1.5 16.7 Fossil Creek Station 2.5 5.8 Eklutna Station 2.0 4.2 Lake Lorraine Substation +SVC 1.0 35.0 48.0 Douglas Substation 3.5 13.0 Gold Creek station 3.5 11.0 / Healy station 1.0 4.5 11.0 Lorraine-Douglas Line 1.0 2.0 30.0 17.5 Douglas -Healy line 1.0 3.0 2.0/*15.0 36.0 Communication 1.0 5.0 4.0 5.0 Cook Inlet fuel security 8.0 25.0 30.0 Battle Creek diversion 43.0 1.0 annual total 82.7 238.6 265.2 134.5 45.4 Homer Electric Association,Inc. Corporate Office Central Peninsula Service Center 3977 Lake Street 280 Airport Way Homer,Alaska 99603-7680 Kenai,Alaska 99611-5280 Phone (907)235-8551 Phone (907)283-583| FAX (907)235-3313 FAX (907)283-7122 DATE:September 26,2012 TO:Bradley Lake Project Participants FROM:Bradley Janorschke,General Manager SUBJECT:HEA Conceptual Proposal to Bradley Participants Background Historically,Chugach Electric Association,Inc.has provided substantially all the electric generation and transmission requirements of Homer Electric Association,Inc.through a combination of resources owned by either Chugach or HEA.In addition to its own Bernice Lake Power Plant,Chugach has dispatched HEA's Nikiski generation and has transmitted power to and from the Kenai Peninsula across a 115 kV transmission line leased from HEA and extending from HEA's Soldotna Substation to Chugach's Quartz Creek Substation (the S/Q Line). Chugach's lease of that line segment and dispatch of HEA's system have been instrumental in enabling Chugach to perform transmission services for Bradley participants in connection with the delivery of Bradley Lake energy. The power supply relationship between HEA and Chugach expires on December 31%,2013.As of that date,Chugach will cease dispatching the HEA system and the lease will terminate.Also, as of that date,the Bernice Lake Power Plant,formerly owned and dispatched by Chugach,will begin to operate solely as a generation resource for HEA.As a result,the principal value of the S/Q Line will be to transmit Bradley Lake energy and serve as a conduit for energy sales from HEA resources. Beginning January 1,2014,HEA will begin operating the Nikiski Combined Cycle Plant (NCC) for its own account.HEA believes that a significant amount of surplus energy,varying in amount from zero to 18 MW,could be generated from the NCC if the plant were operated at its most efficient settings.The surplus energy after 2013 will be available for sale.In addition,prior to 2014,HEA will begin generating energy from the steam produced at the NCC and intends to market this surplus energy as well. HEA has not yet made a commitment to sell the surplus Nikiski energy.Given the current constraints on the segment of the transmission line between the Quartz Creek and University substations,if HEA markets the energy to any other Railbelt customer,the ability of the remaining Bradley Lake Participants to receive their power will be impacted.No contractual or tariff provision currently exists to ensure continued delivery of Bradley Lake energy over the HEA portion of the transmission line to any Bradley participant other than HEA. A Touchstone Energy*®Cooperative Kx 7-26-2 Bradley Lake Project Participants September 25,2012 Page 2 HEA is currently engaging in discussions with potential purchasers of the surplus Nikiski energy. In addition,HEA has,for some time,been engaged in the development of a tariff for its transmission plant,providing for recovery of the costs associated with the use of its system and allowing the continued export of Bradley Lake energy.HEA has also given consideration to alternatives involving the possible sale or lease of all or a portion of the S/Q Line. Concept The concept below describes an entirely different means of disposing of surplus Nikiski energy and making the S/Q Line available to transmit Bradley Lake energy.It is offered here in draft form for the purpose of determining whether there is interest among the Bradley Participants in operating the S/Q Line as a Bradley resource and serving as the market for HEA's surplus Nikiski energy. In short,HEA suggests the parties explore a solution whereby (1)HEA would surrender its right to control the S/Q Line,allowing the line to be used for the priority export of Bradley energy, and (2)in return for HEA giving up its path for firm off-system sales,the Bradley Participants would assure HEA of a market for its surplus Nikiski energy under terms that would be revenue neutral to the Participants. S/Q Line The surrender of control of the S/Q Line could be accomplished by HEA leasing the line to the Bradley Lake Hydroelectric Project under the "additions or expansions”criteria for Optional Project Work.The terms of the lease would be similar to the current Chugach lease.The term would be for five years,with an early termination provision in the event HEA ceased to be the operator of the Bradley Project.HEA would operate and maintain the S/Q Line just as it does the line from the Bradley power plant to Bradley Junction under the terms of the Transmission Facilities Maintenance Agreement. Over the past few years HEA has undertaken considerable effort and incurred significant expense in assessing and maintaining the S/Q Line;we believe its material condition to be good. HEA is willing to share details relative to the material condition of the S/Q Line with the BPMC. Surplus Nikiski Energy If HEA is to give up its ability to make firm sales of power over the S/Q Line,an alternative market for surplus Nikiski energy must be available.Rather than marketing the energy to specific utilities,HEA suggests an arrangement whereby: e The Bradley Participants would take all available surplus Nikiski energy (unless transmission constraints prevented such purchase); e The consideration for surplus Nikiski energy would be the transfer of an "equivalent” volume of Bradley Lake water inventory from the purchasing utility to HEA;and e A Bradley Participant's obligation to take the surplus Nikiski energy would be prorated based upon relative system size. Bradley Lake Project Participants September 25,2012 Page 3 HEA believes that the above concept satisfies HEA's need to market its surplus Nikiski energy and provides the Bradley Lake Participants as a whole with a better opportunity to assure delivery of their Bradley shares than any other available alternative.HEA recognizes that if the above concept is implemented,HEA would be forgoing the opportunity to make firm sales from its Soldotna and Bernice Lake generation facilities;however,this is a concession HEA is willing to make in the interest of achieving a solution that provides relatively equal benefits to all Participants. I look forward to discussing this concept with the Bradley Participants in further detail and I thank you for your consideration. Bradley P.Janorschke Homer Electric Association Cc:Sarah Fisher-Goad,Executive Director,AEA Matanuska Electric Association,Inc -Alaska Railbelt Cooperative Transmission &Electr...Page 1 of 2 Careers at MEA |ContactUs |E-Bill Online Thursday,04 aa) a ARS A\. e EEG \es be fe Bf,a) GAR URI GARTME ASSGEiAn Gn MEMBER SERVICE MY CO-OP SAFETY AND EFFICIENCY OUR COMMUNITY NE' MEA News MEA News:Board of Directors Approves Eklutna Generation Station (EGS)Engineering Contract »During its Augt Alaska Railbelt Cooperative Transmission &Electric Company Alaska's Railbelt region stretches from the Kenai Peninsula north more than 500 miles to Fairbanks.This portion of our state,named for areas reached by the Railroad,is home to 70 percent of Alaska's population.Combined,the Railbelt uses less electricity than a : a small utility in the Lower 48.ALASKA RAILBELT COOPERATIVE TRANSMISSION &ELECTRIC COMPANY Even still,we have six utilities that serve this relatively small amount of electricity over a very large and diverse territory.MEA alone has over 4,000 miles of power lines. In an unprecedented move on January 7,2011,five Railbelt utilities created a new Generation and Transmission utility,the Alaska Railbelt Cooperative Transmission and Energy Company (ARCTEC)to collectively deal with Railbelt energy needs and challenges.After a lengthy initial meeting in the Chugach Electric Board room,Rick Schikora was named Chairman of the Board and MEA's General Manager,Joe Griffith was named President. The five utilities include Chugach Electric Association (CEA),Matanuska Electric Association (MEA),Homer Electric Association (HEA),Seward Electrical System (SES)and Golden Valley Electric Association (GVEA).Municipal Light and Power (ML&P)is the only Railbelt utility to decline membership but will participate and provide ongoing support to ARCTEC. Two board members from each of the founding utilities comprise the ten member board.Along with Chairman Janet Reiser http://www.mea.coop/index.php/my-co-op/alaska-railbelt-cooperative-transmission-and-el...10/4/2012 4 : Matanuska Electric Association,Inc -Alaska Railbelt Cooperative Transmission &Electr...Page 2 of 2 the slate of officers include Vice Chairman Rick Schikora,Secretary Janet Kincaid from MEA,and Treasurer Willard Dunham,Mayor of Seward.The ARCTEC CEO is our own General Manager Joe Griffith. ARCTEC will focus on centralizing efforts to manage future power projects,obtain state funding for electrical infrastructure projects and programs,construct such projects when requested by the member utilities and collectively deal with Railbelt energy needs."ARCTEC is a win/win for the State of Alaska and for every citizen who lives along the Railbelt.Our challenges are daunting but as the new President |have absolute faith that ARCTEC is an innovative step forward in finding solutions to our energy future.For twenty years |have worked to make this G&T a collective voice and today that vision is reality.”stated Griffith. Copyright Matanuska Electric Association 2012 All Rights Reserved http:/Awww.mea.coop/index.php/my-co-op/alaska-railbelt-cooperative-transmission-and-el...10/4/2012 Utilities break ground on Southcentral Power Project Page 1 of 2 + . GQ supre Kee Utilities break ground on Southcentral Power Project 1 Alaska News Chugach Electric Association and Municipal Light &Power broke ground today on the new Southcentral Power Project located at Chugach's headquarters complex at 5601 Electron Drive. SPP is a joint project to construct an efficient,combined-cycle 183-megawatt power plant.The $369 million cost will be shared 70/30 between Chugach and ML&P. Collaborating on construction will save money for the ratepayers of both utilities -as will the advanced technology of the plant which will use less natural gas than current generating units.Those points were noted by speakers. "|am pleased to see the city's utilities working together on such an important project," said Anchorage Mayor Dan Sullivan."This new plant is a step in the right direction as we look to provide reliable service at a reasonable cost for Anchorage's electrical consumers.Citizens will reap the benefits of this new plant for many years to come, which is important as we continue planning for the city's energy future.” Senator Mark Begich was unable to attend in person,but offered his thoughts on the joint effort in a letter read by Susanne Fleek,his statewide director. "The idea for the joint power plant came about during my time as mayor as we were looking for ways to save money and streamline operations of the utilities,”the senator wrote."|am pleased to see this project moving forward as we plan for the energy needs of our communities for years to come." The plant will have three natural gas-fired turbine-generators and one steam turbinegenerator. The units will operate in combined-cycle mode,meaning the hot exhaust from the gas turbines will be captured and used to make steam for the steam turbine. SPP will use only about three-fourths of the natural gas needed to make a kilowatt-hour compared to the best units on the Chugach system today.That means Chugach and ML&P customers will save about $30 million in fuel costs annually once the plant is fully-operational in 2013.Those savings assume a fuel cost of $6.75 per thousand cubic http://www.akbizmag.com/alaska-news-list/10389-utilities-break-ground-on-southcentral-p...4/7/2011 Utilities break ground on Southcentral Power Project Page 2 of 2 * . &6 feet of natural gas,and will grow if the price of fuel increases. Another benefit of the project will be reduced emissions.The production of both nitrogen oxides and carbon monoxide will be significantly less from the combined-cycle Southcentral Power Project than from simple-cycle generation now on the system. Chugach is the largest electric utility in Alaska,providing power for Alaskans throughout the Railbelt through retail,wholesale and economy energy sales. ML&P provides electric service to more than 30,000 customers in a 20-square-mile area of the Municipality of Anchorage.The utility also provides power to Joint Base Elmendorf Richardson and sells electricity for resale to other Railbelt utilities outside its service area.ML&P is owned by the Municipality of Anchorage. http://www.akbizmag.com/alaska-news-list/10389-utilities-break-ground-on-southcentral-p....4/7/2011 MEA power struggle concludes -Mat-Su Valley Frontiersman:News:lawsuit,settlement ...Page 1 of 1 MEA power struggle concludes By ANDREW WELLNER Frontiersman.com |Posted:Saturday,March 3,2012 9:17 pm PALMER -Though the details are murky,it appears Matanuska Electric Association has finally closed the chapter in its history surrounding a 2009 change ip management. The board of directors of MEA dismissed the electric utility's then-general manager Wayne Carmony in the summer of 2009,an act that sent lawsuits flying through Superior Court.The litigation traveled a tangled,years-long path to resolution. Just prior to his own firing,the board directed Carmony to terminate two high-ranking executives -information technology director Bruce Scott and human resources director Tuckerman Babcock. Scott and Babcock filed a lawsuit almost immediately,alleging MEA had not lived up to the contracts they had signed.MEA eventually settled those contracts for $650,000 out of court.They could have owed a total of $1.1 million in severance. But MEA still managed to take that case to trial,with Carmony in its crosshairs.The utility alleged that Carmony had given Babcock and Scott those contracts without proper authorization and should therefore be liable for the $650,000 settlement.A jury disagreed,ruling against MEA. In August 2011,Carmony filed a lawsuit against MEA in Anchorage Superior Court.Early last -month,word got out that Carmony and MEA had settled out of court.Asked for comment at the time,MEA declined,asking for time to speak with its lawyers. "The attorneys are still working out the agreement.When they finish,we will advise you.Until then,we cannot say much other than we have settled the disagreement,”Carmony's replacement, MEA General Manager Joe Griffith,wrote in a Feb.2 email. On Thursday,Griffith said he'd checked with lawyers and couldn't say anything else. "We have a settlement agreement,the details of which are confidential.Sorry I can't reveal more,”Griffith added in another email,before following up by saying,"This is the best I can do under the agreement.” Contact reporter Andrew Wellner at andrew.wellner@frontiersman.com or 352-2270. http://www.frontiersman.com/news/mea-power-struggle-concludes/article_6a2c98b0-65b9-....5/8/2012 adn.com |MEA fires embattled general manager Page 1 of4 4 ety,adn com [PrintPage |[Close Window |®men | Anchorage Daily News MEA fires embattled general manager WAYNE CARMONY:Board also suspends him from his job immediately. By RINDI WHITE rwhite@adn.com (06/16/09 17:12:22) WASILLA --Matanuska Electric Association on Tuesday fired longtime general manager Wayne Carmony and suspended him from his position immediately. ad In a motion that passed 5-2,board members voted to stop negotiating a severance package with Carmony,to proceed with his termination for cause,and to place him on immediate administrative leave.A second motion,which also passed 5-2,required Carmony to give up his keys,leave the building and remain off MEA property without access to his office and computer until the board votes to allow him access.The motions passed with board members Peter Burchell,Janet Kincaid, Katie Hurley,Kit Jones and Lois Lester in favor.Board members David Glines and Larry DeVilbiss opposed both motions. Assistant genera!manager Don Zoerb will act as manager while the company searches for a-eereplacement. The move came after Carmony told the cooperative board of directors last week he's not interested in their severance package if it means consenting to a gag order. Instead he asked the board to either keep him on as general manager or "simply write me a check for what I am owed and we separate." After new board members were voted in last year,the majority of the board shifted from one generally supportive of management to one that is not.The new board majority opposed Carmony's management style and has criticized him for running the cooperative in a way that is outdated,adversarial and that excludes MEA members. Carmony,who has run the company since 1994,offered the two choices to MEA board members in a letter sent Friday to the board and the roughly 125 people who work at MEA.It was in response to a severance letter MEA board members delivered to Carmony earlier that week. Board members voted last week to offer Carmony a severance package.It's the third in a string of management changes the board has made.It directed Carmony in April to terminate TuckermanBabcock,an assistant general manager,and Bruce Scott,director of information technology at the company.At the same meeting,the board voted to begin the process of terminating Carmony. Board members have discussed little about the changes in open session.Closed executive sessions to discuss things that might have a financial or legal impact on the utility are held at nearly every meeting --sometimes more than one.Board president Lois Lester on Monday said the board isn't at liberty to discuss its actions right now. "Once things get squared away,the members will know what it means,"she said."There's so much I can't say or tell." http://www.adn.com/2009/06/16/v-printer/833396/mea-fires-embattled-general-manager.ht...7/12/2012 adn.com |MEA fires embattled general manager Page 2 of4 + Lester could not say what issues must be resolved before she could speak more freely. Carmony not alone If Carmony sues MEA over his contract,he'll be in line behind Scott and Babcock,who filed a civil suit last week against the utility seeking two years'compensation.They contend that they were improperly fired April 15. MEA spokeswoman Lorali Carter said because their employment is in court,she could not release estimates of how much the two men received annually in pay and benefits.A 2007 wage report published in the May 2008 Powerlines,an MEA newsletter,said the MEA IT director was paid $127,363.13. It listed two assistant general managers,one paid $140,060.71 and another $126,310.08. Assuming Babcock,who was hired in 1999,was paid less than the other assistant general manager Don Zoerb,who was hired before Babcock,the tally in salaries for Babcock and Scott for two years would be $507,346.42,based on 2007 salaries. Contract confidential Carmony sent a redacted version of the board's severance proposal to MEA employees Wednesday, along with a note from him wishing the employees well. All parts of the letter spelling out Carmony's employment agreement are blacked out.MEA spokeswoman Lorali Carter said Carmony would not grant an interview while the severance discussions were taking place.On Tuesday,Carmony left the meeting when the board voted to fire him, Carmony's contract is notoriously confidential,so much so that members of the cooperative board of directors and others who have access to it must read it in the human resources office.Making copies is not allowed,nor is talking about seemingly benign details such as when it expires. One aspect that isn't confidential is Carmony's salary.In discussing the contract in November, former MEA human resources director Tuckerman Babcock said Carmony made $232,972.48. The contract is more confidential than most utility leaders'because an MEA board member 13 years ago distributed copies of the contract to the Frontiersman newspaper and to another former board member.Carmony renegotiated his contract to include more confidentiality. Cost in question From the redacted letter Carmony sent to MEA employees,it's not possible to learn how much the board offered to pay him to leave. According to the offer,Carmony could agree to its terms,which would prevent him from suing MEA or helping others sue,or making public statements about the cooperative unless authorized to do so by the board.Or he could refuse the offer and be terminated "with cause,"which would limit his compensation. "Assuming you contest such a 'with cause'termination,there would be risky,expensive and time- consuming litigation for MEA and for you,"the board's letter states. http://www.adn.com/2009/06/16/v-printer/833396/mea-fires-embattled-general-manager.ht....7/12/2012 adn.com |MEA fires embattled general manager Page 3 of 4 ' In his June 10 letter to employees,Carmony says if he accepted the board's offer,he "could not in the future,as a citizen or a member,make public statements regarding the business or affairs of MEA,a Freedom of Speech right guaranteed to me by the 1st amendment to the United States Constitution ..." In his letter to the board Friday,Carmony refused to sign over those rights. "Your obligation to me is not a matter of negotiating a severance package,and my contract does not require me to agree to any terms not already specified in it,"Carmony states. Friends of MEA,a group made up of several former MEA board members,sent a letter of support for Carmony several weeks ago but has otherwise not spoken about the board's severance negotiations with him. "We figured there's nothing we can do to persuade them to do anything different,"said former MEA board president Lee Jordan."The board majority seems hell-bent on getting rid of him no matter what the cost is.” Jordan but said he fears the cost will ultimately be paid by members. Lester said she and other board members don't yet know what the bottom-line cost of settling or severing Carmony's contract will be. She said she doubted the cost would require MEA to raise rates to cover terminating Carmony, Scott or Babcock. "T don't know yet,but I doubt if it will,"she said. Former executives sue MEA WASILLA --Two former Matanuska Electric Association executives are suing the cooperative for what they say are breaches of their employment contracts.The two employees,former assistant general manager Tuckerman Babcock and former information technology director Bruce Scott, were fired in April. The coop's board of directors,which has clashed with long-time general manager Wayne Carmony, instructed Carmony to fire Babcock and Scott "without cause." The two men served in at-will positions.According to a civil complaint filed last week in Superior Court in Palmer by their attorney Susan Orlansky,they were "subject to termination at the discretion of Mr.Carmony."A second clause in the contract states "If Mr.Carmony is no longer general manager of MEA,then MEA may only terminate this agreement with cause"and only with 30 days advance notice. According to the suit,the contracts outline what happens if someone other than Carmony is running the cooperative and what happens if the two men lost their jobs "with cause,"meaning they failed to carry out their duties,or "without cause,"meaning they did not act inappropriately. According to Orlansky's complaint,the contract states if the two were fired "without cause"by someone other than Carmony,the utility must pay them for the remainder of their contract term. Their two-year contracts had just been renewed two weeks prior to their firing. http://Awww.adn.com/2009/06/16/v-printer/833396/mea-fires-embattled-general-manager.ht..._7/12/2012 adn.com |MEA fires embattled general manager Page 4 of 4 . Babcock and Scott argue that the MEA board tried to avoid paying their severance by ordering Carmony to terminate them,and that their firing was not at Carmony's discretion.Their argument is that since they were fired without cause and not at Carmony's discretion,they should have received severance pay. A final paycheck from MEA included payment for two weeks that Scott and Babcock were suspended without pay,but no severance pay according to their complaint. In the complaint,Scott and Babcock say they are entitled to the cash value of the salary and benefits they would have otherwise received until their contracts ended April 1,2011.The complaint does not state that amount,only that it exceeds $100,000. --Rindi White,Anchorage Daily News [Print Page if Close Window 7 Copyright ©Thu Jul 12 13:25:21 UTC-0800 20121900 The Anchorage Daily News (www.adn.com) http://www.adn.com/2009/06/16/v-printer/833396/mea-fires-embattled-general-manager.ht....7/12/2012 RIA Alaska Railbelt Regional Integrated Resource Plan (RIRP)Study Final Report February 2010 BLACK &VEATCH _Building a world of difference: DISCLAIMER ALASKA RIRP STUDY DISCLAIMER STATEMENT In conducting our analysis and in forming the recommendations summarized in this report,Black & Veatch Corporation (Black &Veatch)has made certain assumptions with respect to conditions,events, and circumstances that may occur in the future.In addition,Black &Veatch has relied upon information provided by others.Black &Veatch has assumed that the information,both verbal and written,provided by others is complete and correct;however,Black &Veatch does not guarantee the accuracy of the information,data,or opinions contained herein.The methodologies we utilized in performing the analysis and developing our recommendations follow generally accepted industry practices.While we believe that such assumptions and methodologies,as summarized in this report,are reasonable and appropriate for the purpose for which they are used,depending upon conditions,events,and circumstances that actually occur but are unknown at this time,actual results may materially differ from those projected.Such factors may include,but are not limited to,the ability of the Railbelt electric utilities and the State of Alaska to implement the recommendations and execute the implementation plan contained herein,the regional and national economic climate,and growth in the Railbelt region. Readers of this report are advised that any projected or forecasted financial,operating,growth, performance,or strategy merely reflects the reasonable judgment of Black &Veatch at the time of the preparation of such information and is based on a number of factors and circumstances beyond our control.Accordingly,Black &Veatch makes no assurances that the projections or forecasts will be consistent with actual results or performance. Any use of this report,and the information therein,constitutes agreement that:1)Black &Veatch makes no warranty,express or implied,relating to this report,2)the user accepts the sole risk of any such use,and 3)the user waives any claim for damages of any kind against Black &Veatch.The benefit of such releases, waivers,or limitations of liability shall extend to the related companies,and subcontractors of any tier of Black &Veatch and the directors,officers,partners,employees,and agents of all released or indemnified parties. Black &Veatch i February 2010 ACKNOWLEDGEMENTS ACKNOWLEDGEMENTS ALASKA RIRP STUDY The Black &Veatch project team would like to thank the following individuals for their valuable contributions to this project. Alaska Energy Authority Jim Strandberg,Project Manager Bryan Carey,Project Manager David Lockard,Geothermal and Ocean Energy Program Manager Steve Haagenson,AEA Executive Director Doug Ott,Hydroelectric Program Manager James Jensen,Wind Program Manager Jim Hemsath,Deputy Director,Development Christopher Rutz,Procurement Manager Sherrie Siverson,Administrative Assistant Railbelt Utilities (numerous management personnel from the following Railbelt utilities) e Anchorage Municipal Light &Power e Chugach Electric Association e City of Seward Electric System Advisory Working Group Members e Norman Rokeberg,Retired State of Alaska Representative,Chairman e Chris Rose,Renewable Energy Alaska Project e Brad Janorschke,Homer Electric Association e Carri Lockhart,Marathon Oil Company e Colleen Starring,Enstar Natural Gas Company Debra Schnebel,Scott Balice Strategies e Jan Wilson,Regulatory Commission of Alaska Golden Valley Electric Association Homer Electric Association Matanuska Electric Association Jim Sykes,Alaska Public Interest Research Group Lois Lester,AARP Marilyn Leland,Alaska Power Association Mark Foster,Mark A.Foster &Associates Nick Goodman,TDX Power,Inc. Pat Lavin,National Wildlife Federation -Alaska Steve Denton,Usibelli Coal Mine,Inc. Tony Izzo,TMI Consulting Additional Individuals That Provided Substantive Input to Project e Alan Dennis,Alaska Department of Natural Resources e Bob Butera,HDR,Inc. e Bob Swenson,Alaska Department of Natural Resources e David Burlingame,Electric Power Systems, Inc.(EPS) e Dick Schober,Seattle-Northwest Securities Jeb Spengler,Seattle-Northwest Securities Corporation Joe Balash,Alaska Governor's Office Ken Fonnesbeck,HDR,Inc. Ken Vassar,Birch,Horton,Bittner,Cherot Kevin Banks,Alaska Department of Natural Resources Mark Myers,Alaska Department of NaturalCorporationResources e Harry Noah,Alaska Mental Health Lands e Paul Berkshire,HDR,Inc. Trust Office e Stephen Spain,HDR,Inc. e Harold Heinze,Alaska Natural Gas Development Authority Black &Veatch ii February 2010 PURPOSE AND LIMITATIONS OF THE RIRP ALASKA RIRP STUDY Purpose and Limitations of the RIRP *The development of this RIRP is not the same as the development of a State Energy Plan;nor does it set State policy.Setting energy-related policies is the role of the Governor and State Legislature.With regard to energy policy making,however,the RIRP does provide a foundation of information and analysis that can be used by policy makers to develop important policies. Having said this,the development of a State Energy Policy and or related policies could directly impact the specific alternative resource plan chosen for the Railbelt region's future.As such,the RIRP may need to be readdressed as future energy-related policies are enacted. e This RIRP,consistent with all integrated resource plans,should be viewed as a "directional”plan.In this sense,the RIRP identifies alternative resource paths that the region can take to meet the future electric needs of Railbelt citizens and businesses;in other words,it identifies the types of resources that should be developed in the future.The granularity of the analysis underlying the RIRP is not sufficient to identify the optimal configuration (e.g.,specific size,manufacturer,model,location,etc.)of specific resources that should be developed.The selection of specific resources requires additional and more detailed analysis. e The alternative resource options considered in this study include a combination of identified projects (e.g.,Susitna and Chakachamna hydroelectric projects,Mt.Spurr geothermal project,etc.),as well as generic resources (e.g.,Generic Hydro Kenai,Generic Wind -GVEA,generic conventional generation alternatives,etc.).Identified projects are included,and shown as such,because they are projects that are currently at various points in the project development lifecycle.Consequently,there is specific capital cost and operating assumptions available on these projects.Generic resources are included to enable the RIRP models to choose various resource types,based on capital cost and operating assumptions developed by Black &Veatch.This approach is common in the development of integrated resource plans. Consistent with the comment above regarding the RIRP being a "directional”plan,the actual resources developed in the future,while consistent with the resource type identified,may be:1)the identified project shown in the resource plan (e.g.,Chakachamna),2)an alternative identified project of the same resource type (e.g.,Susitna);or 3)an alternative generic project of the same resource type.One reason for this is the level of risks and uncertainties that exist regarding the ability to plan,permit,and develop each project.Consequently,when looking at the resource plans shown in this report,it is important to focus on the resource type of an identified resource,as opposed to the specific project. e The capital costs and operating assumptions used in this study for alternative DSM/EE,generation and transmission resources do not consider the actual owner or developer of these resources.Ownership could be in the form of individual Railbelt utilities,a regional entity,or an independent power producer (IPP). Depending upon specific circumstances,ownership and development by IPPs may be the least-cost alternative. e As with all integrated resource plans,this RIRP should be periodically updated (e.g.,every three years)to identify changes that should be made to the preferred resource plan to reflect changing circumstances (e.g.,resolution of uncertainties),improved cost and performance of emerging technologies (e.g.,tidal), and other developments. Black &Veatch ill February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents 1.0 -_Executive Summary «0.00...ee eecesssscenescscsecscsscseeasneneescsscsassacsccesseeeesesseaeseesssasaesaseesaceasenenaes 1-1 1.1 Current Situation Facing the Railbelt Utilities...eeeeesseeeeeeeeeeeeeseeneeneenees 1-1 1.2 -Project Overview ou...ee eesseesscseseessesenecsceecscescsecsecsaescasscsassccasassceecsasaceessasseeaseasers 1-3 1.3.Evaluation Scenarios...cece esses eseesesceseesessesesscseeseeseseesersesecessesseeaseeessonsseeseeaceas 1-7 1.4 Summary of Key Input Assumptions...eesseeseeceeceesceeeesseseeecessceeeseeeeerseeeseses 1-8 1.5 -Susitna Analysis...eesesccsesesccsesceerseseeecsceecsesesecssseeasscuacasacseacssseeasscsaceseeasenes 1-8 1.6 Transmission Analysis ...........:cccssssssecssescsessescsscesscescsssseensssesseseseesassesasessseeeeseesas 1-11 1.7 Summary of Results...cc eeeeesseesesceecseseeecsceeescsecscsesesssescassceceesseeeeesaeeesseseeaseee 1-12 1.7.1 Results of Reference Cases .......ccccsesscceseescessessssesessesssrssrensceensesesseseseees 1-13 1.7.2 Sensitivity Cases Evaluated...tees cscseescecceceeseeceseeseeseseetsccaseeeeeeee 1-16 1.7.3.Summary of Results -Economics and Emissions ...............sseseeeseeeees 1-16 1.7.4 Results of Transmission AnalySis .............seseessesseceeeeeeceseeseeeeceeeeteceetseees 1-19 1.7.5 Results of Financial Analysis 00.00.00...tees eeseeseeecscecceceeeeececeatsaseeeesereeee 1-22 1.8 Implementation Risks and Issues...ess eesssecseseecescseeeesescsceeeeseeeeseeeeeesceeeaesees 1-26 1.8.1 General Risks and Issues...cccssetsesseesseesssesssecsessscsssacssecessteesneneeees 1-26 1.8.2 Resource Specific Risks and ISsues............sssseescsseceseesereececeeceseeeeceseeeaes 1-27 1.9 Conclusions and Recommendations .............ccccessssssssesesssescessescerseseneecesseeesaeaeseeseeees 1-29 bPMim ©1001)(0)1 pO 1-29 1.9.2 Recommendations ...........ccccscssssescssssessesesesssscessseeresscssesescssceesrsseensesesensens 1-33 1.10 Near-Term Implementation Action Plan (2010-2012)oo...eeeescecsseceeeeeetsenenes 1-40 1.10.1 General Actions...cc ccceccscssseesseesesssssserssscessssessssssseessesesscsesecanesesaeeres 1-41 1.10.2 Capital Projects...cece esecessesescesssessseescsessseceesesessssesssessesseasaeseensaees 1-43 1.10.3 Supporting Studies and Activities...esses ssescsssesstsseerseseecseateesees 1-44 1.10.4 Other Actions...cece cceseseessssssesscssssesccesseressssessesseseeseresseceseeeaseees 1-45 2.0 --Project Overview and Approach ...........ecscssesesssssssesssesseesesessssssscsassesesesseassaasassserseesseesaces 2-1 2.1 Project OVerVieW .0.....eee ecscesceesceeeseersssssseesessssessscsnssssssenseecsseaesesessassesasseeseeateetetees 2-1 2.2 Project Approach...cscesssssecessssesesessssesssessseensscesesseesessassesssssesasssssnsnaasevassssceneases 2-2 2.3 Modeling Methodology ............ccscsesssssseceseeeesessenesssescecsaseeeseeseseeseeessesesesnsnssesaeares 2-5 2.3.1 Study Period and Considerations...cccscccessssssssessssescsstsssessesereesseneees 2-5 2.3.2 -Strategist®and PROMOD®Overview......ssssssssssscssssessesssssssneesssnesssssnessesses 2-5 2.3.3 Benchmarking...eeeeeeesseessseeccsssccsescescescaseassesasseeecsscssoeesasseaseeenses 2-5 2.3.4 Hydroelectric Methodology..........cccseesecsssssssensssesessenseenseesesseseneeeseeesses 2-6 2.3.5 Evaluation Scenari0s «0.00.0...eeseeeesseseeeceseececeeceesseeesceeesreersecatenseeeaseasscenees 2-7 2.4 Stakeholder Input Process............cssscseseseesssesssessssesesescesssssscscsesenesssecesscsseesessnenseaeaes 2-8 2.5 Role of Advisory Working Group and Membership ............c..-csssssssessssesseseseseseeseees 2-9 Black &Veatch TC-1 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 3.0 Situational Assessment ...............ee eecssesceseseescsceesesesneeceeeecsseaseesseaseneaceaseneseeasecaererseeseseneaeeas 3-1 3.1 Uniqueness of the Railbelt Region 0.0...ect eeeesssscsseseeecseecenseesecseenssesssseeeseecsseeraees 3-2 3.2 --COSt ISSUES 00...eee eeeeesceecseecceeeeceacsceesscescensucsscensensaseasenscevsesesaessneasetsteeesseeeesseeaseceates 3-2 3.3 Natural Gas Issues...eseecsesseeesssececseeeesesecesseeesecsesacaceseassseaassesenecscsesseeeaeee®3-6 3.4 -_Load Uncertainties...eee ceseesssceeesecnsseesecersersccscseesecseeasensseesssceaseceteneaseceeceeeas 3-10 3.5 Infrastructure Issues...tees secseneeeeeeecescscseeacseccsesceacsesesacuascsesceesessseeeeserasseeees 3-10 3.6 Future Resource Options..........ce.eesseeeeeseeeescenecnecsenssesesseeseeeessceseesseacensseaeenseates 3-11 3.7 Political Issues ole eeesecessesesesesceesecsceacscseesceesesacseseeseseesssaverscseesssssseeeeteeeeeees 3-13 3.8 Risk Management ISSUECS...........cccsccsssssssessesesssssecsssecsssssevscsecsesesesestseacarseeeseeneases 3-13 4.0 Description of Existing System 0.0.0...teesessssssessseeseecescsceesseeceececscesssseesscsceusasuceceasasseeceeeeses 4-1 4.1 -Existing Generating ReSOUrCES .0.........ccceseseeseeseecsceecsesecaseeesesesseseesscsesevevesseseereeeees 4-] 4.1.1 Anchorage Municipal Light &Power 00...essssseceeeesecececesceceetseseeeeeenees 4-1 4.1.2 Chugach Electric Association...es eescseeeesceeeeceeeeeseceeceseeseeseeeeanees 4-2 4.1.3 Golden Valley Electric Association...ct eeseeseseecesceseeeeeeeseseneeceeseeeceeees 4-2 4.1.4 Homer Electric Association...tsseeessscescseeeeeeecesceecessetsesecereeseeseeasere 4-3 4.1.5 Matanuska Electric Association .0........te eeeseeseeeseseeseceececeeeceecseeseseeeeeaeneees 4-3 4.1.6 Seward Electric System...cecseessecescsceseeessseceetesseasseeseavarseeeeseeseseeees 4-3 4.1.7 Hydroelectric ReSOUrCES..........seesesceeesceecsescescececesseseecasecseeseacsseceeesesscerees 4-3 4.1.8 Railbelt System...eeseesesetsecsceesscesceesscesseassensssseesnseasaceesaeseeatees 4-5 4.2 Committed Generating ReSOUrces .............seccecessesesseceeeesseneeaeeneseesescceeseacasenesseeeaeeeeas 4-5 4.2.1 Southcentral Power Project «0.0.0...eee ssessseseeseseeeeececeecececeeeecececeeseeeeseneneenes 4-5 42.2 MU&P UNits oo ee cesseeeeesensscseesessenseeseeesseesnscesseesceseeaseesesseseseesenss 4-5 4.2.3 Healy Clean Coal Project 0...ee ecseescsesseseseeceseseeeeseacseeeseecasaceceeeneneeses 4-7 4.24 HEA UNlits oe ceceeesensccsenseeecsecnesseesesseesesenseessessessesseeeserseseneneeneee 4-7 4.2.5 MEA Units...ec eececeececcseecesceeeseesceeesesscacscensseeseeasssseeseeaseeeesaseeseeeeeaees 4-7 4.2.6 City of Seward Diesels oo...ssessecsessceececseeesseneeesesseseeeasacsenseeeeseres 4-7 4.3 Existing Transmission Grid 0...eesscseeecsesesssescsensesescasscsescessessoreeseeeseceeeeeenseenes 4-8 4.3.1 Alaska Intertie 0...eee teeescsesecseceeseseccessecacesscesscessseesseesaeesensacaeesees 4-10 4.3.2 Southern Intertie ee eeeseeeesscnscseeecseseesessesseseeasseeasseseseseesataseneaee 4-10 4.3.3 Transmission LOSS€S...........c:csssessssessesscsscssesessessaseasesseecsensecssesesesseeeseesees 4-11 A.A =Must Run Capacity oo cceccseccessesecssssssessesssssssssseessssnscecsesesassssenesevevsssesseeearas 4-11 5.0 Economic ParametelS...............scsssssscsssscssccsecessscesessccecssssseessesessessassaeeseesesesecsessessesseseeteaeees 5-1 5.1 Inflation and Escalation Rates ..0.........ce essessesescssecesesceeeescseeessseceeesseasececeeeeeacaeeeeees 5-1 5.2 --Fimancing Rate...ccccssssessesesecsesssseseeseeeeesesseeeeeaseccesssceusaseecessessssesssssesssseerssseees 5-1 5.3 Present Worth Discount Rate...tt eeeesesecscesseecsccessessesaeeesececesseceesaeseessscereatees 5-1 Black &Veatch TC-2 February 2010 TABLE OF CONTENTS 6.0 7.0 8.0 9.0 10.0 ALASKA RIRP STUDY Table of Contents (Continued) 5.4 Interest During Construction Interest Rate ...........ccceeeseesseseeseseseneeneeenseeeeaeseeseees 5-1 5.5 -_-Fixed Charge Rates .........ccccesssessscsssecessssssesssssscssssssscsceesssssenseseeeseesasasseseseeeenensaeenenes 5-1 Forecast of Electrical Demand and Consumption..........cc ccesseseseeseeeceseeeeeessseeseecseseseenenes 6-1 6.1 Load Forecast 0.0...eccsssescesssceseeessecscessecseceesessucessesecsesseseeeseeseessssesasseesseassneaseesaeses 6-1 6.2 Load Forecasting Methodology ...........eessessssesescesessreessseectssseeessseseessseseessseneeeenenees 6-1 6.3.Peak Demand and Net Energy for Load Requirements ...............cccssecesseseteeseeetenseeee 6-1 6.4.Significant Opportunities for Increased Loads ............:cccsseeeeeeeteteeeseseseeeeneneneeseenes 6-4 6.4.1 Plug-In Hybrid Vehicles...ee ceeceescssssesssssssssssssseessesesneneseseeeereneeeney 6-4 6.4.2 Electric Space and Water Heating Load.............ccccsesssssssseeseesereeseneeseceees 6-10 6.4.3.Economic Development Loads...eesssesscsesssesseeessersseetsesseseeeseesneaes 6-10 Fuel and Emissions Allowance Price Projections............ccccccscccssssssesseseeeesesetsessesseneeeseeeeees 7-1 7.1 Fuel Price Forecasts .....0......cesscssessssssssssseessssessensssceessesseacseessseeseeeeneenenesaeessnsesenteneeees 7-1 7.1.1.Natural Gas Availability and Price Forecasts.............ccccsssssessseesereseeseneneees 7-1 7.1.2 Methodology for Other Fuel Price Forecast ...........cccscccesseseseeseseeeeeeseeees 7-9 7.1.3 Resulting Fuel Price Forecasts .........ccc sccsssesscsseeseeseeeseeeneeseeeesseseeneseees 7-10 7.2 Emission Allowance Price Projections ............:cccssssssessessssssceeessessesseseeseeseeseesesnens 7-10 7.2.1 -Existing Legislation...lc esesesssceesssssesseesseeeseassessseeesssesseeseseeneeees 7-10 7.2.2 Proposed Legislation ...........ccccsssssscssesscsssscesssssseesescseseeseeeesseneneesereneserees 7-10 7.2.3.Development of COz2 Emission Price Projection............:ccscecssserenereeeees 7-10 Reliability Criteria ...................sescesesceceaeaeneeesssscenesstecenssseessssuesesesssevscesseseseensneeseassesecessaseeseases 8-1 8.1 Planning Reserve Margin Requirement ...............ccssssscsesssessesesenseseensneesseensesesesenees 8-1 8.2 Operating Reserve Margin Requirements...............cccscsesssssseessssesensseeeseeeerseseneseeeeneas 8-1 8.2.1 Spinning ReServes .........csscsscsssesssseseeeeeesscssseseaesssesenseeeesseessesesseeneseneseeeenees 8-1 8.2.2 Non-Spinning Operating Reserves ............cccccsssssseesesseeesecsesesseeseseseneneeees 8-2 8.3.Renewable Considerations...eesseescssssssssetesesessessesessesssesessssneseteneseseessseeeeee 8-2 8.4 Regulation...ee esesssseseeessesesseeesessssssssssssesesesssesssesenesesensssssnesssseseseseseneeeneseaeaes 8-2 Capacity Requirement ...........cccccseessssesssssesessssseseseseneeesseeeneneseseseseeneseesescsesecacananseetenseseeeeeas 9-1 DST61 5)0)AYZanS(6 (Cok ©0)5 (0)9 oo 10-1 10.1 Conventional Technologies ...........ccccsssscsscesseseessssesssssssessesenssersesesenesseassecnenenterses 10-1 10.1.1 Introduction ......eee eee eessssssseseseessssceresesessssessasecsesessesnsaseeeseeseseenenseseees 10-1 10.1.2 Capital,and Operating and Maintenance (O&M)Cost Assumptions.......10-1 10.1.3 Generating Alternatives Assumptions .............ccccccccccssssesessesssessseneeseeceeeeees 10-1 10.1.4 Conventional Technology Options...cc csssseseeeseeeessessecsenseeeeeeees 10-5 10.2 Beluga Unit 8 Repowering..........ccccccssssesessssseseeseseersscsesesteassensseeeseenenesseeseeencasenes 10-17 10.3.GVEA North Pole 1x1 Retrofit...eee eesessereeeeeeescecessssseeseseseesensesesssesseneees 10-17 Black &Veatch TC-3 February 2010 TABLE OF CONTENTS 11.0 12.0 ALASKA RIRP STUDY Table of Contents (Continued) 10.4 Renewable Energy Options...cece eeseesesceecseeessesesnssssssseseecsesscsssnsscssessenees 10-17 10.4.1 Hydroelectric Project Options ...........cesses cesses eeseesteeseenseeeesserenenees 10-17 10.4.2 Ocean (Tidal Wave)Project Option...eceeseeeessssreeseseeseeesseseneeees 10-27 10.4.3 Geothermal Project Option...eeeeseeesenseeeseeseesseseeseesaseessesceeseees 10-32 10.4.4 Wind Project Options 00...eee ee eeseeeseesseeeessessssesseesesesseeseesensoneneeees 10-35 10.4.5 Modular Nuclear Project Option 00.0.0...seseeseseseeeeesceesesseeeeeeeereeeseneess 10-40 10.4.6 Municipal Solid Waste Project Options ........0 cee ees eeeeeeeeeeeeens 10-45 10.4.7 Central Heat and Powe .......cceececcsecssessscssesessessseseesssessesssssenerenseees 10-45 Demand-Side Management/Energy Efficiency ReSOUPCES............ccccsssscssseessseesseseseeeeseees 11-1 V1.1 Introduction...eee eeeeseseeeesseseseesensesensessesensesessassussssessseessssessersssesnseessases 11-1 11.2 Background and Overview ..........:cccceceesssseessseseecsescasessessssssssnecsassseeesecesscseessaseas 11-2 11.2.1 Current Railbelt Utility DSM/EE Programs .........ccc esssssecsecerseseneeerseees 11-2 11.2.2 Literature REViOW ..0......ccc ecccccecscsseesesceeeseseeseesssseessesesseessaceeeneesecssneseeseese 11-4 11.2.3.Characterization of the Customer Base ............cscesecsseessesesseesseeseeeeeeens 11-4 11.3 DSM/EE Potential...ceceeesesseeceeenscscessessescenecesssessssssssssseesssecessasseesssesenensces 11-6 11.3.1 Methodology for Determining Technical Potential...eee 11-6 11.3.2 Intuitive Screening...eee eee ceeeeeeeeeeesesseessssesseaseeseessesessassereesseeese 11-6 11.3.3 Program Design Process.......cccccsscsssscsssssssessssessssssesssesensesseesseesssessneeees 11-7 11.3.4 Achievable DSM Potential from Other Studies 0.00...eee teeeeeees 11-8 11.4 DSM/EE Measure...eee eccsssesscssssecssesesscssssessessesessesesecssessesessecneesseecsssesseeees 11-8 11.5 DSM/EE Program Delivery «00.0...essseessessssscsecesscsssecsssseecessssseserseevesssesessseseaees 11-16 Transmission Project ..........ccssessssesssssescssssssssccessessesssensessensessssesesesesessecneensssseesssnssecetensonseas 12-1 12.1 Existing Railbelt System...ccsssessssesssssscsessseesereesesesssesscnesseeetsseesssesssessenees 12-1 12.2 The GRETC Transmission Concept .0........ccc ceesssseessecsscseessssscsessssesensorsescseeseseeseees 12-3 12.3 Project Categories .........cccescesessssseseeeeeeessssseneseseassssensnssseeesesesssessessecsetesesesensieses 12-4 12.4 Summary of Transmission Analysis Conducted ..............sccsssscssssseseseesesesseseseenees 12-4 12.4.1 Cases Reviewed ............ssecseseescseeesecseeessstecssssesesssssssesessssesssssaseesasenseeasags 12-5 12.4.2 Results of 2060 AnalySis .........ec essesesessescseseeseseeessssesessssescaseseecscseessees 12-6 12.5 Proposed Projects .........sssssssseccssesseseessstesessssssessseesssesessesenesseseresesseneneseeseneesssensenery 12-6 12.6 -Susitna......eeeeseesesseeseneseesesesesesssesssscsssesevsnssssescsesessesesesassseeesensneseeeeseneesenesesersenantees 12-26 12.7 Summary of Transmission Projects ..........ccccscecesesssssesseeeseessessessesneeenensesseesssesenens 12-27 12.8 Other Reliability Projects...cccsssscseseeeeseerscsnssesesssessesessssssssesesensecsesceeeneeeatee 12-30 12.9 Projects Priorities 0.00...cessesesseesesessessenseessesesesesesessnenesesescesesesessnensneeeeessenseeeees 12-31 Black &Veatch TC-4 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 13.0 Summary of Results...cececcssssssssecseeecsssesesessseesenenscesensseseneseceseasseseessessensesesesesenenesenens 13-1 13.1 Results of Reference Cases...se sesssescssescsssssessessscnessseceeseesssesssseseseseeseeenenenees 13-1 13.1.1 Results -DSM/EE Resources............ccccccsscsssesesseseeeseesseeesesessssenseseeesaseeees 13-1 13.1.2 Results -Scenarios 1A/1B Reference Cases .............ccsccsssesssseeeeeeeneneenens 13-2 13.1.3 Results -Scenario 2A Reference Case Results .........cccccsseseeesesseeeeseeeeees 13-3 13.1.4 Results -Scenario 2B Reference Case Results...........ccssesssssssssseesseeees 13-3 13.2 Results of Sensitivity Cases 0...esseseseesssssesesseeessenesenseseeeseesaseesssenssesssaneneeeesenes 13-3 13.2.1 Sensitivity Cases Evaluated.............ccsessesessssessssesesseeesetenessessrensesesesseseees 13-3 13.2.2 Sensitivity Results -Scenarios 1A/1B Without DSM/EE Measures........13-4 13.2.3 Sensitivity Results -Scenarios 1A/1B With Double DSM/EE MEASULES..........eesceseessescecececsessesssccsccssesecaserecaersssscsesessssscsuseesesseenesseensenteate 13-4 13.2.4 Sensitivity Results -Scenarios 1A/1B With Committed Units Included ..........cssecesesesseceeeseseeesececescneeacscserersrsesesessessssssssesessseeersseseeseseeeees 13-5 13.2.5 Sensitivity Results -Scenarios 1A/1B Without CO2 Costs...........cee 13-5 13.2.6 Sensitivity Results -Scenarios 1A/1B With Higher Gas Prices...............13-6 13.2.7 Sensitivity Results -Scenarios 1A/1B Without Chakachamna................13-6 13.2.8 Sensitivity Results -Scenarios 1A/1B With Chakachamna Capital Costs Increased Dy 75%.........sccssssssssssssessssessssssesesesssneetesessssseseseseaeaeseneses 13-6 13.2.9 Sensitivity Results -Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option)Forced ..........cccceseessesessseeseseseeseneeeees 13-7 13.2.10 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option)Forced .0........ecssssssssssssssesssersesssetsnesetsnsseseees 13-7 13.2.11 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expandable Option)Forced.........ccscsesssssssssssesssessenescsseeseeseaeseeseneneesenens 13-7 13.2.12 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expansion Option)Forced ...........sssesssesssesssesescssscessseesesseesessseeecesssersensees 13-8 13.2.13 Sensitivity Results -Scenarios 1A/1B With Susitna (Watana Option)Forced...ececsscsesessssseseecsesesssseseseseseeseeseesssseeneesseasensesnessneeeers 13-8 13.2.14 Sensitivity Results -Scenarios 1A/1B With Susitna (High Devil Canyon Option)Forced ..........cccsssesssessssesseeeseseseenereseseensseseessesessneresees 13-9 13.2.15 Sensitivity Results -Scenarios 1A/1B With Modular Nuclear.................13-9 13.2.16 Sensitivity Results -Scenarios 1A/1B With Tidal...ceesseeenesees 13-10 13.2.17 Sensitivity Results -Scenarios 1A/1B With Lower Coal Capital and Fuel Costs .........cesecessecesceceeeecseeseeseessssssssseeseseesseseseesecssseseseeeerseseesees 13-10 13.2.18 Sensitivity Results -Scenarios 1A/1B With Federal Tax Credits for Renewables.........cccscscssecssesecessseesessecceseevsessssseesssssssssesassesscsesessesevenseses 13-10 Black &Veatch TC-5 February 2010 TABLE OF CONTENTS 14.0 15.0 16.0 ALASKA RIRP STUDY Table of Contents (Continued) 13.3 Summary of Results...scescssssssssessscesssscsssesssecsssssscessasssssserssesssserssecsseeseess 13-11 13.3.1 Summary of Results -ECONOMICS .........c cc cesstsesscesseeseseessssescsessesesaseees 13-11 13.3.2 Summary of Results -EmiSSions.............cccccsssseessesececeecsesesseessenseeseeeees 13-11 13.4 Results of Transmission AnalySis............ccsessssesssscsesesscsessssssescsceseacsssessseoseersees 13-11 13.5 Results of Financial Analysis...ccssssesesesssscesessesseessosesssssessseesesevseseeseerseees 13-16 Implementation Risks and ISsues..............ccsccsccsscesesesssesssesessseessssseseseseeeesesseessensneeeseenensaeees 14-1 14.1 General Risks and Issues .00.0......eececeeessseeeeesscsssscessesessscessessssessssscessssessensesessesegs 14-1 14.1.1 Organizational Risks and Issues...seeseseessseseseeseseseesesceeescsseerseeeees 14-1 14.1.2 Resource Risks and ISSues...........ccscssssesesesssseserseseescessecsseecssssessseseeeseaeees 14-4 14.1.3 Fuel Supply Risks and Issues...ete eseseseseseseeesseseseeesessseneeesseensesseees 14-4 14.1.4 Transmission Risks and ISSues ............ccccssssessssscsecscsesecsesseeeeeseersessesseseees 14-5 14.1.5 Market Development Risks and Issues...........0...cece cseeeeeeseeeeeeeeeees 14-5 14.1.6 Financing and Rate Risks and ISsues...............sceccsssseessesseseseeneeeeesesesenseeees 14-6 14.1.7 Legislative and Regulatory Risks and Issues ...........cccsssssseessesseseeeeeeeee 14-7 14.1.8 Value of Optionality 0.cc eeessseescreresessrsersssssenseesseusersenseeseeeeees 14-7 14.2 Resource Specific Risks and ISSUES ............ccsssssesssesssseseneeseessssesessestencesseeeseenssenens 14-8 14.2.1 Introduction .000..eee cescsseecsssessssesssnscessecsssesesessessecsessserseaeesseeses 14-8 14.2.2 Resource Specific Risks and Issues -Summary ...........0.cccesesescseeseseeeee 14-8 14.2.3 Resource Specific Risks and Issues -Detailed Discussion.....................14-12 Conclusions and Recommendations.....0........sc cseeeeseseeseeeseessseseeeseesaseesessessssesssnecnssssneseeeees 15-1 15.1 COMCIUSIONS..........ceeecessssecesesececescacecescscncrassceeseesesenevsvscsesaescesesestansetsvacsseeeaeseraeesees 15-2 15.2 Recommendations...ceesseesseeeeeseesceseseeseseseesseecsaeessssnsssesseesssesesssseesessesessaees 15-6 15.2.1 Recommendations -General ..0........:cccscsessseescessssseessssecessecessesseseesseseess 15-7 15.2.2 Recommendations -Capital Projects...ese cescseseeceseseseeseterstseeeee 15-11 15.2.3 Recommendations -Other...ee eee tseeeeeseeseessscseesersesseesssesesaeanes 15-12 Near-Term Implementation Action Plan (2010-2012)oo...cscs csescsessseeeessseenenees 16-1 16.1 Gemeral Actions 0.0...eeeeesseessesesessseesessssessnssesesessssessesessaseesseeessesssecsesssseneesesans 16-1 16.2 Capital Projects eee eesceeesseecesessnsssesssecscessesessesesesensesesenesecseceensnsseenssesenseneness 16-3 16.3 Supporting Studies and Activities...ceeeesssssenenseeesesensesessnensessescsenseeeseneness 16-4 16.4 Other Actions 00...eeecsseeseeeessecensesessceassusssscscereesseseseceesessssrsessserssesisseenscessees 16-5 Black &Veatch TC-6 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Appendix A Susitna Analysis Appendix B_Financial Analysis Appendix C Existing Generation Units Appendix D Regional Load Forecasts Appendix E Detailed Results -Scenarios 1A /1B Appendix F Detailed Results -Scenario 2A Appendix G Detailed Results -Scenario 2B Tables Table 1-1 Summary Listing of Issues Facing the Railbelt Region...eecessessssesseseereseeeees 1-3 Table 1-2 Alternative Resource Options Considered...ccsessesssseseesereseeseeesesetseseterseeneesees 1-5 Table 1-3 Susitna SUMMALY 20.0...secs cessesceeecesessssssssesseeesssscsssseecsssecsssesseeessecerersesseeeseenss 1-10 Table 1-4 Summary of Results -ECONOMICS ............ccscsseesssssseeesessesssesseesessessnscensasenneeeeesenss 1-17 Table 1-5 Summary of Results -EMISSIONS ..........cccecssssesesessesesscesseresessctssesesseesssststessseseessees 1-18 Table 1-6 Summary of Proposed Transmission Projects ............::c::ccssscsssscssseesseeeseseseeeessesees 1-19 Table 1-7 Resource Specific Risks and Issues -SUMMALY ...........cccssecesssescesseseesstenesscsseeonees 1-28 Table 1-8 Resources Selected in Scenario 1A/1B Resource Plan...esse eeeseseeeeeseseerseeens 1-35 Table 1-9 Impact of Selected Issues on the Preferred Resource Plan............cccccssesesseeeseeseees 1-36 Table 1-10 Projects Significantly Under Development .............ccccssssesssseeseeesssssstseseeesnenenensaes 1-37 Table 1-11 |Near-Term Implementation Action Plan -General Actions ...............seseeeeeseeeeees 1-41 Table 1-12 |Near-Term Implementation Action Plan -Capital Projects...ccc eseeeeeeeee 1-43 Table 1-13 Near-Term Implementation Action Plan -Supporting Studies and Activities........1-44 Table 1-14 |Near-Term Implementation Action Plan -Other Actions...cess ceseeeeeeeeees 1-45 Table 3-1 Relative Cost per kWh (Alaska Versus Other States)-2007 o0......cccesseesseeseeeeerees 3-4 Table 3-2 Relative Monthly Electric Bills Among Alaska Railbelt Utilities...3-5 Table 4-1 ML&P Existing Thermal Units...ccssceeseseeecesceeeesesseseeceseeseaeensesseneens 4-1 Table 4-2 Chugach Existing Thermal Units ........0....ccccsssssessssssesssseessesesesenssesssseeeseeseserseseeenees 4-2 Table 4-3 GVEA Existing Thermal Units...ccc cesssceccseeesceesesssseeeeessesesecsesnescessesssesnesaaees 4-3 Table 4-4 HEA Existing Thermal UNiits.............ccccccsssssssssesessesseensesesesecseenenesseseseereseeneseseesies 4-3 Table 4-5 Railbelt Hydroelectric Generation Plants .............cscscssssseseseseesesssssseseeseesssesesssenses 4-4 Table 4-6 Hydroelectric Monthly and Annual Energy (MW))............:c:csssssssssesseesesesensseenees 4-4 Table 4-7 Railbelt Installed Capacity...csssssesssesssscssessseessssscesseceesssseesessesssecesseserserssees 4-5 Table 4-8 Railbelt Committed Generating Resources............ccccscsessessseeescsesscrseceesseseceneeesees 4-6 Table 5-1 Cost of Capital and Fixed Charge Rates for the GRETC System...5-2 Black &Veatch TC-7 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 6-1 GRETC's Winter Peak Load Forecast for Evaluation (MW)2011 -2060................6-2 Table 6-2 GRETC's Summer Peak Load Forecast for Evaluation (MW)2011 -2060.............6-2 Table 6-3 GRETC's Annual Valley Load Forecast for Evaluation (MW)2011 -2060............6-3 Table 6-4 GRETC's Net Energy for Load Forecast for Evaluation (GWh)2011 -2060...........6-3 Table 6-5 Projected PHEV Penetration in the American Auto Market ....0.........sesesssssseesseeeeeees 6-4 Table 6-6 Electric Consumption for a PHEV33 PNNL Kinter-Meyer .............:sccscscececeeeeeeeenees 6-5 Table 6-7 Additional Annual Energy Required in the Alaska Railbelt Region from PHEVS......sesscescssecsscesescececescscecesssesceessceccsscsceesaesessecsssuccacsrcasasenesssacseeeeneaeseesesenessensesees 6-5 Table 6-8 Hourly Distribution of PHEV Load on a Typical Day -Alaska Railbelt REGION .......cessessseeseseeeesesesseesesseaesesnessesecansecscseesansseeseusesatensssesessssseussseassecsessseseesaeesies 6-7 Table 6-9 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Energy Requirement............ccc ccs ccsseessscsscessecscescecsessesaeeesseseeseeaseeeaseens 6-9 Table 6-10 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Peak Demand.........cccsccccssssssseesessssseseessscscstsesseseseersesseseesseseseasaeeesesesaees 6-9 Table 6-11 |2007 Natural Gas Consumption for the State of Alaska (Source:EIA)...............0+6-10 Table 6-12 Calculated Railbelt System Energy and Demand by Customer Type for Electric Space and Water Heating ........ccc sessscssssceceesenerseneeseseeeeeeseeseneessseeeeeeaes 6-10 Table 6-13 Potential Economic Development Projects................:s:sccssssecsesecseccetescescasensesteceeees 6-11 Table 6-14 GRETC's Winter Peak Large Load Forecast for Evaluation (MW)2011 - 2060...eececcccceseressecescsceceecscscesecesssceacscucucacsssceceucesacacsceccasaceessesesseassaeasenesesesseeaeaeees 6-12 Table 6-15 |GRETC's Large Load Net Energy for Load Forecast for Evaluation (GWh) ZOD]-2060 one eeeseseecececessseececescececcsescucacarsceeeacscseececescecscensnssseseseesesseesensasseeeaes 6-12 Table 7-1 Representative Risk-Based Metrics for Railbelt Natural Gas Demand Based on Historical Data and Known Changes in Gas Consumption..............:cccecesseeseesees 7-4 Table 7-2 Representative Forecasts of Railbelt Natural Gas Price According to Different Benchmarks...eesceescecessesseersceessceessceeseeaceasereacenssaeacseeneacseeeeseeaeees 7-9 Table 7-3 Nominal Fuel Price Forecasts ($/MMBtu).............ccccccccscssssscsscssscessssesccsesessecssacsane 7-11 Table 7-4 COz Allowance Price Projections 0.0.00...esesesesseccsccsseccssecseccsseeesseseeesenssceeesseeeeeaees 7-13 Table 8-1 Railbelt Spinning Reserve Requirement ..............c:ccssssccscssessssssssessesesssstsesessseneneees 8-1 Table 8-2 Quick-Start Units 2.0.0...cccesccssecsseeesscssecescesseccscecssecescesseccesessaeeseeeensecseresseeseeeeatesses 8-3 Table 10-1 -Possible Owner's Costs..........sc cssssscsssssesssceecccsssscssssescseescescseeaesacsesseesesessseasecanataes 10-2 Table 10-2 Nonrecoverable Degradation Factors 00.0.0...tsccsesssesssessssstseseeseeecsecsceeseeeasaeetatees 10-6 Table 10-3 GE LM6000 PC Combustion Turbine Characteristics 1.00.00...eeeeeseeeeseeeeeeceeeeee 10-8 Table 10-4 GE LM6000 PC Estimated Emissions.......0......sees escsseseescesesseececeeceeseesesenseseneasers 10-8 Table 10-5 ©GELMS100 Combustion Turbine Characteristics...esesessenseeeeceeeeeeneenees 10-10 Black &Veatch TC-8 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 10-6 GE LMS100 Estimated Emissions...cessssesssssceseecseeeeessessesessssseseseetenesaces 10-10 Table 10-7 GE 1x1 6FA Combined Cycle Characteristics 0000...eeeeseeecseeeeeeseeeeeneseeeeees 10-12 Table 10-8 GE 1x1 6FA Combined Cycle Estimated Emissions......0.........sccesseeesseesseeeeeeees 10-12 Table 10-9 GE 2x1 6FA Combined Cycle Characteristics 0.00.0...ese seecseseeeeseseeeeececeeeeseeees 10-13 Table 10-10 GE 2x1 6FA Combined Cycle Estimated Emissions....0....0.....eeceseseeeceseeteeeeseeees 10-13 Table 10-11 Subcritical PC Thermal Performance Estimates..............:ssccsseseceeeresseeeeeeseeeeeeees 10-15 Table 10-12 Subcritical PC Estimated Air Emissions............tc sssssesceseceseseeeeseeeeecsesereeeeeseaees 10-15 Table 10-13 Capital Costs,O&M Costs,and Schedules for the Generating Alternatives (All Costs in 2009 Dollars)..........cccccccscssessesecesssssessesessssssesesseeesesesseeetssesseeseseseeeseees 10-16 Table 10-14 AEA Recommended Funding Decisions -Hydro...eeeeeeseecsseeeseeseceeteceneenees 10-18 Table 10-15 Susitna SUMMALY ..0....ee eee eeeseseeeeeeseeeeccsceecsccescseseeaceeseeseaceeeacsesenscsseceessesseeeasees 10-21 Table 10-16 Average Annual Monthly Generation from Susitna Projects (MWh)................+10-23 Table 10-17 Monthly Average and Annual Generation...eeeeeseeeeceseeenersceeseseseeeneeeeees 10-25 Table 10-18 Glacier Fork Hydroelectric Project Average Monthly Energy Generation ..........10-26 Table 10-19 AEA Recommended Funding Decisions -Wind...eeeseececseseseseeeececeeeeeeeeeeees 10-36 Table 11-1 |Current Railbelt Electric Utility DSM/EE-Related Activities...eee 11-2 Table 11-2 DSM/EE-Related Literature SOUrCES ..........cee tstseeeeseeesessceeseeeseesesssseseseeseesenseneey 11-4 Table 11-3 -Railbelt Electric Utility Customer Base...tee eseeseceseeceseeeeceeeseeceecseeceetereesesees 11-5 Table 11-4 Residential and Commercial DSM/EE Technologies Evaluated...11-10 Table 11-5 Input Assumptions -Residential DSM/EE MeasureS............cccsssssssssseeserereetseeees 11-12 Table 11-6 Input Assumptions -Commercial DSM/EE Measures .............::sscscsseesseseeeeeeseeees 11-13 Table 12-1 Summary of Proposed Transmission Projects ..........cccssssessssssssesssseeessessseseeneeees 12-27 Table 13-1 =Summary of Results -ECONOMICS 00.0...csc sescssesesesessesetscerscseessatscneeeeneseseneesenes 13-12 Table 13-2 Summary of Results -EMISSIONS «0.1.0.0...ccc sccsseeseeretersessssesssescssesscrecsesseteteeseees 13-13 Table 13-3.Summary of Proposed Transmission Project «0.0.0...sccssssssesssssscesssseeeeseererereseeees 13-14 Table 14-1 Resource Specific Risks and Issues -SUMMALY ............cccccesssseseetsesssesesssseeeeeeseetees 14-9 Table 14-2 Resource Specific Risks and Issues --DSM/EE ..........scsssccsssssesssesensssssneneeeseeneeee 14-13 Table 14-3.Resource Specific Risks and Issues -Generation -Natural Gas...eeeeeeeee 14-16 Table 14-4 -_Resource Specific Risks and Issues -Generation -Coal..........cccseesssessseseeeseees 14-18 Table 14-5 Resource Specific Risks and Issues -Generation -Modular Nuclear..................14-19 Table 14-6 |Resource Specific Risks and Issues -Generation -Large Hydro............ccee 14-20 Table 14-7 Resource Specific Risks and Issues -Generation -Small Hydro...eee 14-21 Table 14-8 -Resource Specific Risks and Issues -Generation -Wind ...........ceeeeeseseseeeeene 14-22 Table 14-9 Resource Specific Risks and Issues -Generation -Geothermal .............c:cceee 14-23 Black &Veatch TC-9 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 14-10 Resource Specific Risks and Issues --Generation -Solid Waste.............::ceee 14-24 Table 14-11 Resource Specific Risks and Issues -Generation -Tidal ............eseeeseseeseseeeees 14-25 Table 14-12 Resource Specific Risks and Issues -Transmission.............:cssecseeeseseeseeeneseneeees 14-27 Table 15-1 Resources Selected in Scenario 1A/1B Resource Plan...eseeseeeeeesereeeeeeeee 15-8 Table 15-2 -Impact of Selected Issues on the Preferred Resource Plan...........cccessessesseesseeeeeees 15-9 Table 15-3 -Projects Significantly Under Development ....0......estes eesceeeseeeececeseceeeeeenceeeeeaes 15-10 Table 16-1 |Near-Term Implementation Action Plan -General Actions 00.0.0...teeeeeeeeeeeeeees 16-1 Table 16-2 Near-Term Implementation Action Plan -Capital Projects...tesssseseseseeseees 16-3 Table 16-3.Near-Term Implementation Action Plan -Supporting Studies and Acctivities........16-4 Table 16-4 |Near-Term Implementation Action Plan -Other Actions..............ccccssssseseseeseees 16-5 Figures Figure 1-1 --_Evaluation Scemari0S............c.ccccscssesesessscesseesessscesesssensssesessssescsceresssssssssscsssnenscseenees 1-7 Figure 1-2 |Comparison of Project Cost Versus Installed Capacity...tee ssesesesseeeeeenee 1-11 Figure 1-3.Impact of DSM/EE Resources Base Case Load Forecast..........cccssseessesesees 1-14 Figure 1-4 -Results -Scenarios 1A/1B Reference Cases .............:ssesssssesssessesescerseceeneesscnescatecnens 1-15 Figure 1-5 --Results -Scenario 2A Reference Case .........ecesssssescseeesescessesseccsesescsceeterecetersearees 1-15 Figure 1-6 Results -Scenario 2B Reference Case ............c.ceesssseeseeseseereeeeesenenseeesscnesensecasacaees 1-15 Figure 1-7 Location of Proposed Transmission Projects (Without Susitna)..........0...:cceseeees 1-20 Figure 1-8 |Required Cumulative Capital Investment for Each Base Case..............cssssesseeeeees 1-23 Figure 1-9 Required Cumulative Capital Investment (Scenarios 1A/1B)Relative to Railbelt Utility Debt Capacity 0...see eseseseesesesereeseseeeesasseeeeserseeetereesees 1-24 Figure 1-10 Cumulative Present Value Cost -Selected Reference and Sensitivity Cases.........1-30 Figure 1-11 Annual Wholesale Power Cost -Selected Reference and Sensitivity Cases ..........1-30 Figure 1-12 Comparison of Results -Scenario 1A/1B Versus Committed Units SeMSitivity Case........cccesseesessesesessssssesesssssesscssessessscesssnsecesessoscessesesasssssseesasaseeeaeas 1-32 Figure 1-13 Interplay Between GRETC and Regional Integrated Resource Plan.......................1-33 Figure 2-1 -Project Approach Overview...........ccccssscsssssesesesssessesssseseneesssssssesscsceeseseseseceseseesssaeaes 2-3 Figure 2-2 --_Evaluation Scenarios.............ccccccsscssssssesseesescscscsesescssesesssesesseessecescnseesessssessssnsssesseneas 2-7 Figure 2-3 -Elements of Stakeholder Involvement ProcesS..............ssssssssesosssssesesessssessesessessseaees 2-8 Figure 3-1 |Summary of Issues Facing the Railbelt Region............ccssscsesssesesseeceseescesessensersces 3-1 Figure 3-2.|Chugach's Reliance on Natural Gas ...........sssssesssssessesesssseseneesssesessesesesseseseeessneeeseneaes 3-8 Figure 3-3.Overview of Cook Inlet Gas Situation...........cceccccsesessesesestesesesseeneneesenenenessenereeneees 3-8 Black &Veatch TC-10 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 3-4 -Historical Chugach Natural Gas Prices Paid 0.0...ssesseseseesesseeeseseeesseeereeeseeseees 3-9 Figure 3-5 |Chugach Residential Bills Based on 700 kWh Consumption...eeeeeseeeeeeeeee 3-9 Figure 4-1 Railbelt Existing Transmission System as Modeled...............esseesesceseseeeeeeeeeeeeeseees 4-9 Figure 6-1 US Daily Driving Patterns oo...cceceesetseecseeeseteeeeessecesseeeeassesasseesereseceeeaeeees 6-6 Figure 6-2 PHEV Daily Charging Availability Profile 0.ee eeeeeeseneeeceeeeeeeeceseeeesees 6-6 Figure 6-3.-Hourly Distribution of PHEV Load on a Typical Day -Alaska Railbelt REGION oo...eeteecesseecccesesessseeeseessssscessessacansscsussessseeseassevsseasaseasssesssasaaseeseesseeseceaeeeeass 6-8 Figure 6-4 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Energy Requirement...eeessescseescsseseesseeccsesseeetsceaceessceseereetseesesees 6-8 Figure 6-5 =Impact of a High PHEV Penetration Scenario Over the Alaska RailbeltSystem's Peak Demand...........cee eecsecesseceeeeeseseeeeseseseeccseeeeasscsesseseeeesseceesneaeseeeneseeaes 6-9 Figure 7-1._-_-Results of a Risk-Based Gas Supply Model Simulation for the Year 2017 ..............7-2 Figure 7-2.|Schematic Summary of the Probabilistic Gas Supply Forecast Model .....................7-3 Figure 7-3 |Comparison of Natural Gas Price Forecasts Relevant to Railbelt Resource PLANS...ee eeeescsessssscecsseccseecsccacsccsecaeecsecassessssasssssessassessesessceessceasaceaseasereaeaesnsaseaeeneas 7-8 Figure 9-1 Scenario 1A Capacity Requirements Without DSM/EE ...........cceeessssesetceeetseceeeesees 9-2 Figure 9-2.Scenario 1A Capacity Requirements With DSM/EE...........eesssescesseseretseeeseeeneeesees 9-3 Figure 9-3.Scenario 2A Capacity Requirements Without DSM/EE........ee eee eeeneeeeeeeeereees 9-4 Figure 9-4 Scenario 2A Capacity Requirements With DSM/EE......0....teeseseeeseseseceeceesescenenenees 9-5 Figure 9-5 Scenario 1A Capacity Requirements Including Committed Units Without DSMIEE1...ee eecscssescseesesescscscessscsssccsssccecsssesevesseesessesesesessesseeasseueeassceesacaesssesesssesases 9-6 Figure 9-6 |Scenario 1A Capacity Requirements Including Committed Units WithDSMIEEuececeecscssescseescsescscssesssesssecaesceceassesessssesaeessessssuenesscsesassaesesesssesasseasseeesseneeeaes 9-7 Figure 10-1 Proposed Susitna Hydro Project Location (Source:HDR)...........cscscscesseeeeeeeeees 10-19 Figure 10-2 Comparison of Project Cost Versus Installed Capacity ..........sseeeeeeeeeceseeeeeeeeeee 10-22 Figure 10-3.Proposed Chakachamna Hydro Project Location (Source:TDX)..........ceeseeeee 10-24 Figure 10-4 Blue Energy's Tidal Bridge With Davis Turbine (Source:Blue Energy).............10-28 Figure 10-5 Cutaway Graphic of a Mid-Range-Scale Vertical Axis Tidal Turbine (Source:Blue Energy)..........sscssssesesssssessseescesessssessesesescseeeseseseesseesseseeeaeereeaeeeees 10-29 Figure 10-6 Proposed Layout of the Turnagain Arm Tidal Project (Source:Little Susitna Construction Co.and Blue Energy of Canada)...........ccseecsssesseeeseeeeeeeseeteneeesees 10-30 Figure 10-7 Turnagain Arm Tidal Project Monthly Generation ................ccsceseesesceneneseneaee 10-31 Figure 10-8 Simplified Binary Geothermal Power Plant Process (Source:Ormiat)................10-33 Figure 10-9 Simplified Geothermal Combined Cycle Power Plant Process (Source: Oral)o...cccceecsesseesssscssesscsssseseesessecseesscsesessssssseressesecsessessessessesseetesececeecsscseersess 10-33 Black &Veatch TC-11 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 10-10 Estimated Mount Spurr Project Development Plan (Source:Ormat)...............0 10-35 Figure 10-11 Visual Simulation of Fire Island Wind Generation Project (Source: CIRI/enXco Joint Venture)...........cccsscecssesseescssesscssssscseesscnsessceussseesssssasssssssssssase 10-37 Figure 10-12 Preliminary Site Arrangement and Interconnection Route (Source: CIRI/enXco Joint Venture)oo...cece ccssssscsssscscsscsessssssscsscsscscssssscssscesssessessseens 10-38 Figure 10-13 Kenai Peninsula,Nikiski (Source:Kenai Winds LLC)...eeeseceeseteeeeens 10-39 Figure 10-14 Simplified Hyperion Power Cycle Diagram (Source:Hyperion Power Generation)oc ccecccccsccsccesscssccssescssccssscssecvscsssuscesescssscessesseccssssacessessaeseseessseeasees 10-41 Figure 10-15 Requested Potential Advanced Reactor Licensing Application Timelines (Source:NRC February 20,2008 Briefing Presentation Slide)..........esecseeeeeee 10-43 Figure 10-16 NRC New Licensing Process and Construction Timelines for New Reactors (Source:NET website).........c..cccccccscssesesssssssessscessessssesecsesecssesesssecssssesseresusseesseeseees 10-44 Figure 11-1 Common DSM/EE Program Development Process .............:scssssscsseeeeseseseseeseeseaees 11-7 Figure 11-2 EPRI/EEI Assessment:West Census Region Results .............:ssssssseesececeeetseeeeeees 11-9 Figure 12-1 Railbelt Transmission System Overview..............:eccscsssceccesececeseeseseseseeseseseeeesseesens 12-2 Figure 12-2 Bernice Lake Power Plant to International 230 kV Transmission Line (New Build)oo.ec eccessssecsccessessessessccsccssscsecsecseussuecsscsussesssssscasssssssessessecsssssossssssesscassenees 12-7 Figure 12-3.Soldotna to Quartz Creek 230kV Transmission Line (Repair andReplacement)0.0.0.0...cesseccsecesessecesessesseseseeescsssceesseecseseseasscasececssesseseresessesessesseseesss 12-8 Figure 12-4 Quartz Creek to University 230kV Transmission Line (Repair and Replacement)..........ccccccsscsssecesssescsssesscscacecseccesesevavenesesessssssaceesesuceanessaeeneesessereeseeaeees 12-9 Figure 12-5 Douglas to Teeland 230 kV Transmission Line (Repair and Replacement).........12-10 Figure 12-6 Lake Lorraine to Douglas 230 kV Transmission Line (New Build).................12-12 Figure 12-7 Douglas to Healy 230 kV Transmission Line (Upgrade).............csscssssseseseeseeesees 12-13 Figure 12-8 Douglas to Healy 230 kV Transmission Line (New Build)...ceeeesseeeeeeesees 12-14 Figure 12-9 Eklutna to Fossil Creek 230 kV Transmission Line (Upgrade)............cc.csssseeeee 12-15 Figure 12-10 Healy to Gold Hill 230 kV Transmission Line (Repair and Replacement)...........12-16 Figure 12-11 Healy to Wilson 230 kV Transmission Line (Upgrade).0.0......te tesceseseseseeeeeeees 12-17 Figure 12-12 Soldotna to Diamond Ridge 115 kV Transmission Line (Repair and Replacement)........:..sescccsessesesssecsseceseescesesecesessscsansucuseeeceasesssecaescseseseecscaceeeeseeeass 12-18 Figure 12-13 Lawing to Seward 115 kV Transmission Line (Upgrade)..........ccceeeeeeeeeeeeeeees 12-19 Figure 12-14 Eklutna to Lucas 230 kV Transmission Line (Repair and Replacement)..............12-20 Figure 12-15 Lucas to Teeland 230:kV Transmission Line (Repair and Replacement).............12-21 Figure 12-16 Fossil Creek to Plant 2 230 kV Transmission Line (Upgrade)0.0.0.0...cesses 12-22 Figure 12-17 Pt.Mackenzie to Plant 2 230 kV Transmission Line (Repair and Replacement).........ccccscessesssecessessssssessssessssnsssscsssssesssssceresscsnsssesssessessasssaseseneacecaees 12-23 Black &Veatch TC-12 February 2010 TABLE OF CONTENTS Figure 12-18 Figure 12-19 Figure 12-20 Figure 12-21 Figure 12-22 Figure 13-1 Figure 13-2 Figure 13-3 Figure 13-4 Figure 13-5 Figure 13-6 Figure 13-7 Figure 13-8 Figure 13-9 Figure 13-10 Figure 13-11 Figure 13-12 Figure 13-13 Figure 13-14 Figure 13-15 Figure 13-16 Figure 13-17 ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Bernice Lake to Soldotna 115 kV Transmission Line (Rebuild)...12-24 Bernice Lake to Beaver Creek to Soldotna 115 kV Transmission Line (Rebuild)......c cc eesescsscssecssssessescesescesesessesssceeessssseacsecasssesesaeseesseresessesessasscescssenenes 12-25 Susitna to Gold Creek 230 kV Transmission Line ......0.......cesessseesesececececeseetersees 12-26 Location of Proposed Transmission Projects (Without Susitna)...............:.:c 12-28 Location of Proposed Transmission Projects (With Susitna)..............ceeseseeeeeeees 12-29 Impact of DSM/EE Resources -Base Case Load Forecast............ssscscsseseseceeeseees 13-2 Results -Scenarios 1A/1B Reference Cases ............ssessseesesseseseesesenessseeseeeseseesesees 13-2 Results -Scenario 2A Reference Case ............sscsscessessssseseceseecssecetseneneseesesestseessnses 13-3 Results -Scenario 2B Reference Case...ss eessssesscssseseecececesecenesescsscnsaeeeeseneees 13-3 Sensitivity Results -Scenarios 1A/1B Without DSM/EE Measures .............:.006 13-4 Sensitivity Results -Scenarios 1A/1B With Double DSM/EE Measureeg...............13-4 Sensitivity Results -Scenarios 1A/1B With Committed Units Included................13-5 Sensitivity Results -Scenarios 1A/1B Without CO2 Costs .0......tee eeeeeeeeeeeeeeees 13-5 Sensitivity Results -Scenarios 1A/1B With Higher Gas Prices ..0........cecseeesesseees 13-6 Sensitivity Results -Scenarios 1A/1B Without Chakachamma..............ccsecseesenees 13-6 Sensitivity Results -Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option)Forced .............essssssseseesecssecececescecececeseneceseseseseseaeeeesenss 13-7 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Non- Expandable Option)Forced 0.0...ce ecteseessseseseneeesceneeenenesenessasseeeesaesesteesseeeees 13-7 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expansion Option)Forced .0........c cc cscscssesescseseecseeceeseesesesenescssaceeseeneeseeneasseseseaeaaes 13-8 Sensitivity Results -Scenarios 1A/1B With Susitna (Watana Option)Forced.......13-8 Sensitivity Results -Scenarios 1A/1B With Susitna (High Devil Canyon Option)Forced 0...cscssssescscsssessscssscscecesesescsessssesssseasessesesececusseneseseneansnsesaeeess 13-9 Sensitivity Results -Scenarios 1A/1B With Modular Nuclear............0...ceeeee 13-9 Sensitivity Results -Scenarios 1A/1B With Tidal oo...eee seeeeeeeeeeereeeeaeees 13-10 Figure 13-18 Sensitivity Results -Scenarios 1A/1B With Lower Coal Capital and Fuel COStS.....cs ceeesecessseeseesssscssseecscecssscscsnsesssnscsesescsssasssesssecsssrscessusessssssesssesosssegesneceracaseees 13-10 Figure 13-19 Sensitivity Results -Scenarios 1A/1B With Federal Tax Credits for Remewable ..........ccccsscccessssssesssssssssesssesssssssssesseseesssesssessesssssessessecscsvscseasassenanseaeasees 13-10 Figure 13-20 Required Cumulative Capital Investment for Each Reference Case .....................13-16 Figure 13-21 Required Cumulative Capital Investment (Scenarios 1A/1B)Relative to Railbelt Utility Debt Capacity occ ecceesssssssesessssesserecssssscsesseesanseaseeenees 13-17 Black &Veatch TC-13 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 15-1 Cumulative Present Value Cost --Selected Reference and Sensitivity Cases.........15-3 Figure 15-2 Annual Wholesale Power Cost Selected Reference and Sensitivity Cases ..........15-3 Figure 15-3 Comparison of Results -Scenario 1A/1B Versus Committed Units Sensitivity Case........cccececesssseccssceeeseesssecesssssssssssecsssssscscasssscssscasesacaeasseasseeeereeaees 15-5 Figure 15-4 Interplay Between GRETC and Regional Integrated Resource Plan..............::00 15-6 Black &Veatch TC-14 February 2010 ACRONYM LIST ALASKA RIRP STUDY ACEEE American Council for an Energy Efficiency Economy ACESA American Clean Energy and Security Act of 2009 AEA Alaska Energy Authority AHFC Alaska Housing Finance Corporation AIDEA Alaska Industrial Development and Export Authority APA Alaska Power Authority ARRA American Recovery and Reinvestment Act of 2009 Bef Billion cubic feet BESS Battery energy storage system CCS Carbon capture and sequestration CFL Compact fluorescent light C/A Commercial and industrial CO,Carbon dioxide COLA Construction and operation license application CTG Combustion turbine generator CWIP Construction-work-in-progress DPP Delta Power Plant DR Demand response DSM/EE Demand-side management/energy efficiency EEI Edison Electric Institute EIA Energy Information Administration EPA Environmental Protection Agency EPRI Electric Power Research Institute EPS Electric Power Systems,Inc. FERC Federal Energy Regulatory Commission FGD Flue gas desulfurization GE General Electric GHG Greenhouse gas GRETC Greater Railbelt Energy &Transmission Company G&T Generation and transmission GVEA Golden Valley Electric Association HAGO High atmospheric gas oil HCCP Healy Clean Coal Project HDR HDR,Inc. HEA Homer Electric Association HHV Higher heating value HPC High-pressure compressor HPT High-pressure turbine HSRG Heat recovery steam generators Hz Hertz IP Intermediate-pressure IPP Independent power producers Black &Veatch AL-1 February 2010 ACRONYM LIST ALASKA RIRP STUDY IRS Interconnection requirements studies JV Joint venture kV Kilovolt KW Kilowatt kWh Kilowatt-hour LEEP Lighting Energy Efficiency Pledge LNG Liquefied natural gas LP Low-pressure LPT Low-pressure turbine MEA Matanuska Electric Association ML&P Anchorage Municipal Light &Power MMBtu Million British thermal units MMcf/d Million cubic feet per day MSW Municipal solid waste MW Megawatt NO,Nitrogen oxides OEM Original equipment manufacturer O&M Operations and maintenance PC Pulverized coal PHEV Plug-in hybrid vehicles PPA Power purchase agreement PPM Part per million REC Renewable energy credits REGA Railbelt Electrical Grid Authority RIRP Railbelt Integrated Resource Plan ROW Right-of-way RPM Revolutions per minute RPS Renewable portfolio standard SBC System benefit charge SCR Selective catalytic reduction SES City of Seward Electric System SILOS Shed in lieu of spin SNW Seattle-Northwest Securities Corporation SO,Sodium oxides SVC Static var compensators TOU Time-of-use ULSD Ultra-low sulfur diesel USDA-RUS United States Department of Agriculture/Rural Utilities Service WGA Western Governor's Association Black &Veatch AL-2 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.0 EXECUTIVE SUMMARY In response to a directive from the Alaska Legislature,the Alaska Energy Authority (AEA)was the lead State agency for the development of a Regional Integrated Resource Plan (RIRP)for the Railbelt Region.This region is defined as the service areas of six regulated public utilities,including:Anchorage Municipal Light & Power (ML&P),Chugach Electric Association (Chugach),Golden Valley Electric Association (GVEA), Homer Electric Association (HEA),Matanuska Electric Association (MEA),and the City of Seward Electric System (SES).A seventh utility,Doyon,is interconnected to the Railbelt system serving the military bases of Fort Greely,Fort Wainwright,and Fort Richardson,but is not included in this RIRP. The purpose of this document is to provide the results of the RIRP study.This section includes the following subsections: e Current Situation Facing the Railbelt Utilities e Project Overview e Evaluation Scenarios e Summary of Key Input Assumptions e Susitna Analysis e Transmission Analysis e Summary of Results e Implementation Risks and Issues e Conclusions and Recommendations e Near-Term Implementation Plan (2010-2012) Some Definitions Three Discrete Tasks e REGA means "Railbelt Electrical e REGA study determined the business structure Grid Authority”for future Railbelt generation and transmission ¢GRETC means "Greater Railbelt (G&T) Energy &Transmission Company”e GRETC initiative is the joint effort between e RIRP means "Railbelt Integrated Railbelt Utilities and AEA to unify Railbelt G&T Resource Plan”e RIRP is the economic plan for future capital investment in G&T and in fuel portfolios that GRETC would build,own and operate 1.1 Current Situation Facing the Railbelt Utilities The Railbelt generation,transmission,and distribution infrastructure did not exist prior to the 1940s.At that time,citizens in separate areas within the Railbelt region joined together to form four cooperatives (Chugach, GVEA,HEA,and MEA)and two municipal utilities (ML&P and SES)to provide electric power to the consumers and businesses within their service areas.Collectively,these utilities are referred to as the Railbelt utilities. Black &Veatch 1-1 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY The independent and cooperative decisions made over time by utility managers and Boards,as well as the State,in a number of areas have significantly improved the quality of life and business environment in the Railbelt.Examples include: e Infrastructure Investments -the State and the Railbelt utilities have made significant investments in the region's generation and transmission infrastructure.Examples include the Alaska Intertie and Bradley Lake Hydroelectric Plant. e Gas Supply Investments and Contracts -ML&P took a bold step when it purchased a portion of the Beluga River Gas Field,a decision that has produced a significant long-term benefit for ML&P's customers and others within the Railbelt.Additionally,Chugach was able to enter into attractive gas supply contracts.These decisions have resulted in historical low gas prices which have significantly offset the region's inability to achieve economies of scale in generation due to its small size. e Innovative Solutions -GVEA's Battery Energy Storage System (BESS)is one example of numerous innovative decisions that have been made by utility managers and Boards to address issues that are unique to the Railbelt region. e Joint Operations and Contractual Arrangements -over the years,the Railbelt utilities have joined together for joint benefit in terms of coordinated operation of the Railbelt transmission grid and have entered into contractual arrangements that have benefited each utility. The evolution of the business and operating environment,and changes in the mix of stakeholders,presents new dynamics for the way decisions must be made.This Current changing environment poses significant challenges for the Railbelt utilities and,indeed,Situation all stakeholders.In fact,it is not an overstatement to say that the Railbelt is at a +Limited redundancy historical crossroad,not unlike the period of time when the Railbelt utilities were *Limited economies originally formed.of scale -Dependence on Categories of issues facing the Railbelt utilities include:fossil fuels e Uniqueness of the Railbelt region +Limited Cook Inlet ©Cost issues gas deliverability .and storageeNaturalgasissues; sas *Aging G&TeLoaduncertaintiesinfrastructure e Infrastructure issues «Inefficient fuel use e Future resource options *Difficult financingePoliticalissuesDuplicati ..«Duplicative G&TeRiskmanagementissuesexpertise Table 1-1 provides a listing of the issues within each of these categories.A detailed discussion of these issues is provided in Section 3. Black &Veatch 1-2 February 2010 SECTION 1 EXECUTIVE SUMMARY Table 1-1 ALASKA RIRP STUDY Summary Listing of Issues Facing the Railbelt Region Uniqueness of the Railbelt Region Size and geographic expanse Limited interconnections and redundancies Load Uncertainties e Stable native growth e Potential major new loads Political Issues e Historical dependence on State funding e Proper role for State Cost Issues Relative costs -Railbelt region versus other states Relative costs -among Railbelt utilities Economies of scale Infrastructure Issues e Aging generation infrastructure ¢Baseload usage of inefficient generation facilities e Operating and spinning reserve requirements Risk Management Issues e Need to maintain flexibility ¢Future fuel diversity e Aging infrastructure e Ability to spread regional risks Natural Gas Issues Historical dependence Expiring contracts Declining developed reserves and deliverability Historical increase in gas prices Potential gas supplies and prices Future Resource Options ¢Acceptability of large hydro and coal e Carbon tax and other environmental restrictions e Optimal size and location of new generation and transmission facilities e Limited development - renewables e Limited development - demand-side management/energy efficiency (DSM/EE) programs 1.2 Project Overview The goal of this project is to minimize future power supply costs,and maintain or improve on current levels of power supply reliability, through the development of a single comprehensive RIRP for the Railbelt region.The intent of the RIRP project,as stated in the AEA request-for-proposal,is to provide: An up-to-date model that the utilities and AEA can use as a common database and model for future planning studies and analysis. An assessment of loads and demands for the Railbelt electrical grid for a time horizon of 50 years including new potential industrial demands. RIRP Objective Function Minimize regional power supply costs,and maintain or improve current reliability,as opposed to minimizing power supply costs for any individual utility. Projections for Railbelt electrical capacity and energy growth,fuel prices,and resource options. An analysis of the range of potential generation resources available,including costs,construction schedule,and long-term operating costs. Black &Veatch 1-3 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY A schedule for existing generating unit retirement,new generation construction,and construction of backbone transmission lines that will allow the future Railbelt electrical grid to operate reliably under a transmission tariff which allows access by all potential power producers,and with a postage-stamp rate for electric energy and demand for the entire Railbelt as a whole. A long-term schedule for developing new fuel supplies that will provide for reliable,stable pricedelectricalenergyfora50-year planning horizon. A short-term schedule that coordinates immediate network needs (i.e.,increasing penetration level of non-dispatchable generation,such as wind)within the first 10 years of the planning horizon,consistent with the long-term goals. A short-term plan addressing the transition from the present decentralized ownership Current Situation *Limited redundancy *Limited economies of scale Dependence on fossil fuels Limited Cook Inlet gas deliverability *Plan that economically +Competes generation, RIRP Study schedules what,when, and where to build,based on available fuel and energy supplies 50-year time horizon transmission,fuel supply and DSM/energy and control to a unified G&T entity that and storage efficiency options identifies unified actions between utilities *Aging G&T .|+Considers CO,regulation that must occur during this transition period.infrastructure "|+Includes renewable *Inefficient fuel use energy projectseAdiverseportfolioofpowersupplythat includes,in appropriate portions,renewable and alternative energy projects and fossil fuel projects,some or all of which could be provided by independent power producers (IPPs). e Acomprehensive list of current and future generation and transmission power infrastructure projects. *Difficult financing *Arrives at a plan to build future infrastructure for minimum long-run cost to ratepayers +Duplicative G&T expertise *Considers fuel supply options and risks The alternative resource options considered in the RIRP analysis are shown in Table 1-2. Black &Veatch conducted the REGA study for the AEA and the final report was released in September 2008. That study evaluated the feasibility of the Railbelt utilities forming an organization to provide coordinated unit commitment and economic dispatch of the region's generation resources,generation and transmissionsystemplanning,and project development.As a result of that study,legislation was proposed to create GRETC with a 10-year transition period to achieve these goals.This RIRP is based on the GRETC concept being implemented from the beginning of the study's time horizon. Black &Veatch had primary responsibility for conducting this Railbelt RIRP.In addition to Black &Veatch, three other AEA contractors (HDR Inc.,Electric Power Systems,Inc.,and Seattle-Northwest Securities Corporation)played important roles in the development of the RIRP. HDR updated work from the mid-1980s on the Susitna Hydroelectric Project and developed the capital and operating costs,as well as the generating characteristics,for several smaller-sized Susitna projects.HDR'sworkwasusedbyBlack&Veatch in the Strategist®and PROMOD®modeling discussed below.HDR's report summarizing the results of its work is provided in Appendix A. Electric Power Systems,Inc.(EPS)assisted in the evaluation of the region's transmission system. Black &Veatch 1-4 February 2010 SECTION 1 EXECUTIVE SUMMARY Table 1-2 ALASKA RIRP STUDY Alternative Resource Options Considered Demand-Side Management/Energy Efficiency (DSM/EE)Measure Categories Conventional Generation Resources Renewable Resources Residential e Appliances e Water Heating e =Lighting e =Shell e Cooling/Heating Commercial e Water Heating e Office Loads e Motors e =Lighting e Refrigeration e Cooling/Heating Simple Cycle Combustion Turbines e LM6000 (48 MW) e LMS100 (96 MW) Combined Cycle e 1x1 6FA (154 MW) e 2X1 6FA (310 MW) Coal Units ¢Healy Clean Coal e Generic -130 MW Hydroelectric Projects e Susitna e Chakachamna e Glacier Fork e¢Generic Hydro -Kenai e Generic Hydro -MEA Wind e BQ Energy/Nikiski e Fire Island e Generic Wind Kenai e Generic Wind -GVEA Geothermal e Mt.Spurr Municipal Solid Waste e Generic -Anchorage e Generic -GVEA Other Resources Included in Sensitivity Cases e Modular Nuclear e =Tidal Seattle-Northwest Securities Corporation (SNW)developed the financial model used to determine the overall financing costs for the portfolio of generation and transmission projects developed as part of this project,and evaluated the impact of some financial options that could be used to address financing issues and mitigating related rate impacts.The results of SNW's analysis are provided in Appendix B. Additional information regarding Black &Veatch's approach to the completion of this study is provided in Section 2. Black &Veatch 1-5 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Purpose and Limitations of the RIRP e The development of this RIRP is not the same as the development of a State Energy Plan;nor does it set State policy.Setting energy-related policies is the role of the Governor and State Legislature.With regard to energy policy making,however,the RIRP does provide a foundation of information and analysis that can be used by policy makers to develop important policies. Having said this,the development of a State Energy Policy and or related policies could directly impact the specific alternative resource plan chosen for the Railbelt region's future.As such,the RIRP may need to be readdressed as future energy-related policies are enacted. e This RIRP,consistent with all integrated resource plans,should be viewed as a "directional”plan.In this sense,the RIRP identifies alternative resource paths that the region can take to meet the future electric needs of Railbelt citizens and businesses;in other words,it identifies the types of resources that should be developed in the future.The granularity of the analysis underlying the RIRP is not sufficient to identify the optimal configuration (e.g.,specific size,manufacturer,model,location,etc.)of specific resources that should be developed.The selection of specific resources requires additional and more detailed analysis. e The alternative resource options considered in this study include a combination of identified projects (e.g., Susitna and Chakachamna hydroelectric projects,Mt.Spurr geothermal project,etc.),as well as generic resources (e.g.,Generic Hydro -Kenai,Generic Wind -GVEA,generic conventional generation alternatives, etc.).Identified projects are included,and shown as such,because they are projects that are currently at various points in the project development lifecycle.Consequently,there is specific capital cost and operating assumptions available on these projects.Generic resources are included to enable the RIRP models to choose various resource types,based on capital cost and operating assumptions developed by Black &Veatch.This approach is common in the development of integrated resource plans. Consistent with the comment above regarding the RIRP being a "directional”plan,the actual resources developed in the future,while consistent with the resource type identified,may be:1)the identified project shown in the resource plan (e.g.,Chakachamna),2)an alternative identified project of the same resource type (e.g.,Susitna);or 3)an alternative generic project of the same resource type.One reason for this is the level of risks and uncertainties that exist regarding the ability to plan,permit,and develop each project.Consequently, when looking at the resource plans shown in this report,it is important to focus on the resource type of an identified resource,as opposed to the specific project. e The capital costs and operating assumptions used in this study for alternative DSM/EE,generation and transmission resources do not consider the actual owner or developer of these resources.Ownership could be in the form of individual Railbelt utilities,a regional entity,or an independent power producer (IPP). Depending upon specific circumstances,ownership and development by IPPs may be the least-cost alternative. ¢As with all integrated resource plans,this RIRP should be periodically updated (e.g.,every three years)to identify changes that should be made to the preferred resource plan to reflect changing circumstances (e.g.,resolution of uncertainties),improved cost and performance of emerging technologies (e.g.,tidal),and other developments. Black &Veatch 146 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.3 Evaluation Scenarios Black &Veatch,in collaboration with the Advisory Working Group that was assembled by the AEA for this project,developed four Evaluation Scenarios;Black &Veatch then developed a 50-year resource plan for each of these Evaluation Scenarios. The primary objective of these Evaluation Scenarios was to evaluate two key drivers.The first driver was to look at what the impacts would be if the demand in the region was significantly greater than it is today;of primary interest was to see if higher demands would result in greater reliance on large generation resource options and allow for more aggressive expansion of the region's transmission network. The second driver was to determine the impact associated with the pursuit of a significant amount of renewable resources over the 50-year time horizon. As a result,Black &Veatch evaluated the four Evaluation Scenarios shown in Figure 1-1. Figure 1-1 Evaluation Scenarios %Base Case Scenario 1A Scenario 1B ® o Le K8 High Growth Scenario 2A Scenario 2BCase Least Cost Force 50% Level of Renewables by 2025 (Energy) The key assumptions underlying each Evaluation Scenario include: e Scenario 1 -Base Case Load Forecast o Current regional loads with projected growth All available resources -fossil fuel,renewables,and DSM/EE Probabilistic estimate of gas supply availability and prices Deterministic price forecasts for other fossil fuels Emissions including CO,costs Transmission system investments required to support selected resources Scenario 1A -Least Cost Plan Scenario 1B -Force 50%Renewables0000000 Black &Veatch 17 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY e Scenario 2 -Large Growth Load Forecast o Significant growth in regional loads due to economic development efforts or large scale electrification (e.g.,economic development loads,space and water heating fuel switching,and electric vehicles) Base case resources,fuel availability/price forecasts and CO,costs Transmission system investments required to support selected resources Scenario 2A -Least Cost Plan Scenario 2B -Force 50%Renewables0000 1.4.Summary of Key Input Assumptions The completion of this RIRP required the development of a large number of assumptions in the following categories: e Section 4 -Description of Existing System,including information on existing generation resources, committed generation resources,and the existing Railbelt transmission network. e Section 5 -Economic Parameters,including inflation rates,financing rates,present worth discount rate,interest during construction rate,and fixed charge rates. e Section 6 Forecast of Electrical Demand and Consumption,including 50-year peak demand forecasts and net energy for load requirements. e Section 7 -Fuel and Emissions Allowance Price Projections,including price forecasts for various fuels and emission allowance price projections. e Section 8 -Reliability Criteria,including the region's planning and operating reserve margin requirements. e Section 9 -Capacity Requirements,including the region's capacity requirements over the 50-year planning horizon. e Section 10 -Supply-Side Options,including an overview of the supply-side resource option input assumptions used in this study,including both conventional technologies and renewable energy options. e Section 11 -DSM/EE Resources,including a summary of the methodology and assumptions that Black &Veatch used to evaluate potential DSM/EE measures. e Section 12 -Transmission Projects,including an overview of the transmission projects required to improve the overall reliability of the region's transmission network and connect the generation resources included in the alternative resource plans that were developed as part of this project. 1.5 Susitna Analysis A hydroelectric project on the Susitna River has been studied for more than 50 years and is again being considered by the State of Alaska as a long term source of energy.In the 1980s,the project was studiedextensivelybytheAlaskaPowerAuthority(APA)and a license application was submitted to the FederalEnergyRegulatoryCommission(FERC).Developing a workable financing plan proved difficult for a project of this scale.When this existing difficulty was combined with the relatively low cost of gas-fired electricity in the Railbelt and the declining price of oil throughout the 1980s,and its resulting impacts upon the State budget,the APA terminated the project in March 1986. In 2008,the Alaska State Legislature authorized the AEA to perform an update of the project.That authorization also included this RIRP project to evaluate the ability of this project and other sources of energy to meet the long term energy demand for the Railbelt region of Alaska.Of all the hydro projects in the Railbelt region,the Susitna projects are the most advanced and best understood. Black &Veatch 18 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY HDR was contracted by AEA to update the cost estimate,energy estimates and the project development schedule for a Susitna River hydroelectric project.The initial alternatives reviewed were based upon the 1983 FERC license application and subsequent 1985 amendment which presented several project alternatives: Watana.This alternative consists of the construction of a large storage reservoir on the Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unit powerhouse with a total installed capacity of 1,200 MW. Low Watana Expandable.This alternative consists of the Watana dam constructed to a lower height of 700 feet and a four-unit powerhouse with a total installed capacity of 600 MW.This alternative contains provisions that would allow for future raising of the dam and expansion of the powerhouse. Devil Canyon.This alternative consists of the construction of a 646-foot-high concrete dam at theDevilCanyonsitewithafour-unit powerhouse with a total installed capacity of 680 MW. Watana/Devil Canyon.This alternative consists of the full-height Watana development and the Devil Canyon development as presented in the 1983 FERC license application.The two dams and powerhouses would be constructed sequentially without delays.The combined Watana/Devil Canyondevelopmentwouldhaveatotalinstalledcapacityof1,880 MW. Staged Watana/Devil Canyon.This alternative consists of the Watana development constructed in stages and the Devil Canyon development as presented in the 1985 FERC amendment.In stage one the Watana dam would be constructed to the lower height and the Watana powerhouse would only have four out of the six turbine generators installed,but would be constructed to the full sized powerhouse.In stage two the Devil Canyon dam and powerhouse would be constructed.In stage three the Watana dam would be raised to its full height,the existing turbines upgraded for the higherhead,and the remaining two units installed.At completion,the project would have a total installed capacity of 1,880 MW. As the RIRP process defined the future Railbelt power requirement it became evident that lower cost hydroelectric project alternatives,that were a closer fit to the energy needs of the Railbelt,should be sought. As such,the following single dam configurations were also evaluated: Low Watana Non-Expandable.This alternative consists of the Watana dam constructed to a height of 700 feet,along with a powerhouse containing four turbines with a total installed capacity of 600 MW.This alternative has no provisions for future expansion. Lower Low Watana.This alternative consists of the Watana dam constructed to a height of 650 feet along with a powerhouse containing three turbines with a total installed capacity of 380 MW.Thisalternativehasnoprovisionsforfutureexpansion. High Devil Canyon.This alternative consists of a roller-compacted concrete (RCC)dam constructed to a height of 810 feet,along with a powerhouse containing four turbines with a total installed capacity of 800 MW. Watana RCC.This alternative consists of a RCC Watana dam constructed to a height of 885 feet, along with a powerhouse containing six turbines with a total installed capacity of 1,200 MW. The results of this study are summarized in Table 1-3 and a comparison of project size versus project cost is shown in Figure 1-2. Black &Veatch 1-9 February 2010 ALASKA RIRP STUDY Table 1-3 Susitna Summary Firm 2008 Schedule Dam Ultimate Capacity,|Construction (Years from Height Capacity |98%Cost Energy Start of Alternative Dam Type (feet)(MW)(MW)($Billion)(GWh/yr)|Licensing) Lower Low Watana |Rockfill 650 380 170 $4.1 2,100 13-14 Low Watana Non-Rockfill 700 600 245 $4.5 2,600 14-15 expandable Low Watana Rockfill 700 600 245 $4.9 2,600 14-15 Expandable Watana Rockfill 885 1,200 380 $6.4 3,600 15-16 Watana RCC RCC 885 1,200 380 $6.6 3,600 15-16 Devil Canyon Concrete Arch |646 680 75 $3.6 2,700 14-15 High Devil Canyon |RCC 810 800 345 $5.4 3,900 13-14 Watana/Devil Rockfill/Concr |885/646 1,880 710 $9.6 7,200 15-20 Canyon ete Arch Staged Rockfill/Concr |885/646 1,880 710 $10.0 7,200 15-24 Watana/Devil ete Arch Canyon Black &Veatch 1-10 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-2 Comparison of Project Cost Versus Installed Capacity $120 0 $10.0 |Watana/Devil Canyon a =$80: = &1 3 :WatanaRCC B watanaZ$60 |ro &High Devil Canyon 3 Low Watana Expandable #Low Watana Non- =$4.0 LowerLow Watana &expandable 4 Devil Canyon $20 | $00:cee .:a coe ce -wee , Q 200 400 600 800 1000 1200 1400 1600 1300 2000 Installed Capacity (MW) In all cases,the ability to store water increases the firm capacity over the winter.Projects developed with dams in series allow the water to be used twice.However,because of their locations on the Susitna River,not all projects can be combined.The Devil Canyon site precludes development of the High Devil Canyon site but works well with Watana.The High Devil Canyon site precludes development of Watana but could potentially be paired with other sites located further upstream. The detailed results of the HDR Susitna study,except for the detailed appendices,are provided in Appendix A.One of the appendices contained within the HDR report (Appendix D),which is not included in Appendix A of this report,addresses the issue of the potential impact of climatic changes on Susitna'sresourcepotential;this appendix can be viewed in the full HDR report which is available on the AEA web Site. 1.6 Transmission Analysis An important element of this RIRP was the analysis of transmission investments required to integrate the generation resources in each resource plan,ensure reliability and enable the region to take advantage of economy energy transfers between load areas within the region. The fundamental objective underlying the transmission analysis was to upgrade the transmission system over a 10-year period to remove transmission constraints that currently prevent the coordinated operation of all the utilities as a single entity. Black &Veatch 1-11 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY The study included all assets 69 kV and above.These assets,over a transition period,may flow into GRETC and form the basis for a phased upgrade of the system into a robust,reliable transmission system that can accommodate the economic operation of the interconnected system.The transmission analysis also assumed that all utilities would participate in GRETC with planning being conducted on a GRETC (i.e.,regional) basis.The common goal would be the tight integration of the system operated by GRETC. Potential transmission investments in each of the following four categories were considered: e Transmission systems that need to be replaced because of age and condition (Category 1) e Transmission projects required to improve grid reliability,power transfer capability,and reserve sharing (Category 2) Transmission projects required to connect new generation projects to the grid (Category 3) e Transmission projects to upgrade the grid required by a new generation project (Category 4) In developing the transmission system,reliability remains a significant focus.Redundancy is one way to increase reliability,but may not be the only way to improve or maintain reliability. The results of Black &Veatch's transmission assessment are discussed later in this section. 1.7.Summary of Results The purpose of this subsection is to summarize the results of the RIRP analysis.We begin by providing a summary of the base case results for each of the four Evaluation of scale energy supplies Scenarios.We then provide a +Dependence on *50-year time horizon RIRP comparative summary of the fossil fuels «Competes generation,Results economic and emission results Limited Cook Inlet transmission,fuel supply Increased for all base cases and gas deliverability and DSM/energy DSM/energy sensitivity cases.This is and storage efficiency options efficiency followed by a summary of the Aging G&T (|?Considers CO,regulation -Increased results of the transmission infrastructure "|+Includes renewable "|renewables analysis that was completed +Inefficient fuel use energy projects Reduced and.finally,the results of the *Difficult financing *Arrives at a plan to build dependence ,ys future infrastructure for on natural gasfinancialanalysis.More *Duplicative G&T a ....expertise minimum long-run cost to Increaseddetailedinformationregardingpratepayerstransmission the results of the RIRP study is provided in Section 13. Current Situation *Limited redundancy +Limited economies RIRP Study +Plan that economically schedules what,when, and where to build,based on available fuel and *Considers fuel supply options and risks Black &Veatch 1-12 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.7.1 Results of Reference Cases In this subsection,we provide summaries of the reference case results for each of the following four Evaluation Scenarios: e Scenario 1A -Base Case Load Forecast -Least Cost Plan e Scenario 1B -Base Case Load Forecast -Force 50%Renewables e Scenario 2A -Large Growth Load Forecast -Least Cost Plan e Scenario 2B -Large Growth Load Forecast -Force 50%Renewables Our analysis shows that Scenarios 1A and 1B result in the same resources and,consequently,the same costs and emissions.In other words,the cost of achieving a renewable energy target of 50 percent by 2025 (Scenario 1B)is no greater than the cost of the unconstrained solution (Scenario 1A).This result applies only if a large hydroelectric project is built.Hereafter,we will refer to Scenarios 1A and 1B together. We begin with a summary of the impact that DSM/EE measures have on the region's capacity and annual energy requirements.This is followed by summary graphics and information for each of the Evaluation Scenarios.Detailed model output for each of the reference cases are provided in Appendices E-G. 1.7.1.1 DSM/EE Resources As discussed in Section 11,Black &Veatch screened a broad array of residential and commercial DSM/EE measures.Based on this screening,21 residential and 51 commercial DSM/EE measures were selected forinclusionintheRIRPmodels,Strategist®and PROMOD®%,as potential resources to be selected. Based upon the relative economics and savings of these screened residential and commercial DSM/EE measures,from the utility perspective,all of the residential and commercial DSM/EE measures were selected in each of the four Evaluation Scenarios.As discussed in Section 11,the penetration of the measures was based on technology adoption curves for DSM/EE studies from the BASS model;additionally,DSM/EEmeasuresaretreatedbyStrategist®and PROMOD®as a reduction to the load forecast from which the alternative supply-side options are considered for adding generation resources. As can be seen in Figure 1-3,DSM/EE measures result in a significant impact on the region's capacity and energy requirements.After the initial program start-up years,DSM/EE measures reduce the region's capacity requirements by approximately 8 percent.A similar level of impact is also shown for annual energy requirements. Black &Veatch 1-13 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-3 Impact of DSM/EE Resources -Base Case Load Forecast Demand (MW)Energy Requirements (MWh) -Without DSM/EE -Without DSM/EE 1,400 -With DsM/EE 8,000,000 -DSM/EE L 1,200 =7,000,000 =3 6,000,000 | 1,000 =_-=-5,000,000=800 E E =4,000,000 g &3,000,000 400 2>2,000,000200 2014J20174202042023|202620292032203820412044204720502053205620592038204120442047205020532056205920112014|20232026|20292032It should be noted that this study did not include an evaluation of innovative rate designs (e.g.,real-time pricing and demand response rates),nor did it consider the potential benefits of a Smart Grid,and the associated widespread implementation of smart meters.These options could result in even greater reductions in peak demand and annual energy usage. A Note Regarding DSM/EE Resources e This RIRP demonstrates the economic potential of DSM/EE resources. e Due to limited Alaska-specific DSM/EE-related data and experience,Black &Veatch limited the amount of DSM/EE resources included in the preferred resource plan. e Additional analysis,both by Black &Veatch as part of this study and by others,along with the experience of other utilities throughout the US,suggest that additional levels of DSM/EE resources may be economic. e However,given the lack of Alaska-specific data and experience,additional data gathering and analysis is required before the optimal level of DSM/EE resources can be determined. e Furthermore,the isolated nature of the Railbelt coupled with severe weather conditions,dictates caution with regard to the ultimate reliance on DSM/EE resources. e Additionally,the limited penetration of electric space heating in the Railbelt region affects the ultimate level of DSM/EE savings. e To develop the full potential of DSM/EE resources,it will be necessary to collect baseline end-use saturation,customer and vendor information,as well as address the reduction in utility margins that result from the implementation of DSM/EE programs. e Additionally,Black &Veatch believes that a regional approach to the development of DSM/EE programs (e.g.,GRETC)will be more successful than if the six Railbelt utilities develop independent DSM/EE programs. Black &Veatch 1-14 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.7.1.2 Results -Scenarios 1A/1B Reference Cases Figure 1-4 Results -Scenarios 1A/1B Reference Cases n000 Capacity By Resource Type 3000 Energy By Resource Type 1800 |g | 1600 eeTidal - #@ Ocean Tidal oa .5000 aWird:um B Municipal Sold Waste = ' |Municipal Soid Waste=1200 B Geothermal 3 s000 »Geothermal 2 100 &Hydro 5 &Hydro s @ Purchase Power =5000 @ Purchase Powerg0FuelOilZz@FuelOM 600 @ Nuclear 2000 @ Nuclear 400 @Coal : wCoal 200 @ Natral Gas 1000 . ; .@ NatralGas 0 >SESSS8883 88 532222 8 SE58 88 8882 52528238 1.7.1.3 Results -Scenario 2A Reference Case Figure 1-5 Results -Scenario 2A Reference Case 3500 Capacity By Resource Type 14000 Energy By Resource Type 3000 Ocean Tidal 12000 =Wind .@ Ocean Tidal_?"§Mricipat Sold Waste 10000 wirdA2000.f . @ Muricipal Solid Waste8000Pras. 4 Bb Hydro é . ; &Hydro. &1500 m Purchase Power 2 6000 .™Purchase Power6FuelOi!:oe Fuet Oi 1000 @ Nuclear 4000 ; . .@ Nuclear BCoal :oO m Coal 500 m Neural Gas 2000 Co .4.Gm Natural Gas "oer SRERRSESEESE ES oon oom EERE OME SK TESS ERE EEZFRSRSSKRSRSSRSRSRKRERRRRRRRLSKARTALSSSSSSISRSS 1.7.1.4 Results -Scenario 2B Reference Case Figure 1-6 Results --Scenario 2B Reference Case 3500 Capacity By Resource Type 14000 Energy By Resource Type 3000 =Ocean Tidal600BWind ®Ocean Tidal =8 Muricipal Solid Waste .ani |Sotawé2000=Geothermal B a Goutenna oeE&Hydro 5 &Hydro<1500 @ Purchase Power =Purchase Power <@ Fuel Oil é @ Fuel Oil 1000 @ Nuclear @ Nuclear @Coal Coal $00 @ Natal Gas @ Natrat Gas 0 Black &Veatch 1-15 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY A Note Regarding Emerging Technologies e Inthe economic analysis underlying this RIRP,Black &Veatch used current cost and performance assumptions for all generation technology options considered.This was done because of the inherent difficulty in predicting the future cost and performance of technologies,particularly emerging technologies (e.g.,on-shore and off-shore wind and tidal). e Recent improvements in wind-related costs and performance demonstrate the potential for emerging technologies.Conversely,the cost and performance of conventional resource technologies are stable at best and not likely to improve. e Further development of tidal power should be encouraged due to its resource potential in the Railbelt region.Although this technology is not commercially available,in Black &Veatch's opinion,at this point in time,it has the potential to become economic within the planning horizon. e These diverging cost and performance trends are one reason why this RIRP needs to be updated periodically;by so doing,emerging technologies can be added to the region's preferred resource plan as their costs and performance improve. 1.7.2 Sensitivity Cases Evaluated The following sensitivity cases were evaluated: e Scenarios 1A/1B Without DSM/EE Measures Scenarios 1A/1B With Double DSM/EE Measures Scenarios 1A/1B With Committed Units Included Scenarios 1A/1B Without CO,Costs Scenarios 1A/1B With Higher Gas Prices Scenarios 1A/1B Without Chakachamna Scenarios 1A/1B With Chakachamna Capital Costs Increased by 75% Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option)Forced Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option)Forced Scenarios 1A/1B With Susitna (Low Watana Expandable Option)Forced Scenarios 1A/1B With Susitna (Low Watana Expansion Option)Forced Scenarios 1A/1B With Susitna (Watana Option)Forced Scenarios 1A/1B With Susitna (High Devil Canyon Option)Forced Scenarios 1A/1B With Modular Nuclear Scenarios 1A/1B With Tidal Scenarios 1A/1B With Lower Coal Capital and Fuel Costs Scenarios 1A/1B With Federal Tax Credits for Renewables 1.7.3.Summary of Results -Economics and Emissions In this subsection,we provide a comparative summary of the economic and emissions results for all of the reference cases and sensitivity cases. 1.7.3.1.Summary of Results -Economics Table 1-4 summarizes the economic results,including: e Cumulative present value cost (from the utility perspective) e Average wholesale power cost (from the utility perspective) e Renewable energy in 2025 e Total capital investment Black &Veatch 1-16 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-4 Summary of Results -Economics Cumulative Average Renewable Present Value Wholesale Energy in |Total Capital Cost Power Cost 2025 Investment Case ($000,000)(¢per kWh)(%)($000,000) Scenarios Scenario 1A $13,625 17.26 62.32%$9,087 Scenario 1B $13,625 17.26 62.32%$9,087 Scenario 2A $20,162 19.75 42.64%$14,111 Scenario 2B $21,109 20.68 65.83%$18,805 Sensitivities 1A/1B Without DSM/EE Measures $14,507 17.40 67.10%$8,603 1A/1B With Double DSM $12,546 15.89 65.15%$8,861 1A/1B With Committed Units Included $14,109 17.87 46.84%$8,090 1A/1B Without CO2 Costs $11,206 14.20 49.07%$8,381 1A/1B With Higher Gas Prices $14,064 17.82 61.95%$9,248 1A/1B Without Chakachamna $14,332 18.16 38.06%$7,719 1A/1B With Chakachamna Capital Costs $14,332 18.16 38.06%$7,719 Increased by 75% 1A/1B With Susitna (Lower Low Watana $15,228 19.29 61.01%$12,421 Non-Expandable Option)Forced 1A/1B With Susitna (Low Watana Non-$15,040 19.05 63.01%$15,057 Expandable Option)Forced 1A/1B With Susitna (Low Watana $15,346 19.44 63.01%$15,588 Expandable Option)Forced 1A/1B With Susitna (Low Watana $14,854 18.82 66.90%$14,069 Expansion Option)Forced 1A/1B With Susitna (Watana Option)Forced $15,683 19.87 70.97%$13,211 1A/1B With Susitna (High Devil Canyon $14,795 18.74 66.92%$11,633 Option)Forced 1A/1B With Modular Nuclear $13,841 17.53 60.51%$9,105 1A/1B With Tidal $13,712 17.37 65.52%$9,679 1A/1B With Lower Coal Fuel and Lower $13,625 17.26 62.32%$9,087 Coal Capital Costs 1A/1B With Tax Credits for Renewables $12,954 16.41 67.56%$9,256 Black &Veatch 1-17 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.7.3.2 Summary of Results -Emissions Table 1-5 summarizes the emissions-related results of all of the reference and sensitivity cases.The following information is provided for each case: e CO,emissions e NO,emissions e SO,emissions Table 1-5 Summary of Results -Emissions Co,NO,SO, Case ('000 tons)('000 tons)('000 tons) Scenarios Scenario 1A 80,259,047 124,215 21,768 Scenario 1B 80,259,047 124,215 21,768 Scenario 2A 152,318,066 133,642 24,476 Scenario 2B 125,498,202 140,897 26,348 Sensitivities 1A/1B Without DSM/EE Measures 88,181,350 139,179 30,605 1A/1B With Double DSM 69,324,920 131,299 18,994 1A/1B With Committed Units Included 91,212,598 136,946 16,482 1A/1B Without CO2 Costs 100,753,030 134,031 23,960 1A/1B With Higher Gas Prices 78,323,066 121,700 25,232 1A/1B Without Chakachamna 105,643,650 133,577 25,700 1A/1B With Chakachamna Capital Costs Increased by 75%105,643,650 133,577 25,700 1A/1B With Susitna (Lower Low Watana Non-Expandable 82,328,762 127,921 22,124 Option)Forced 1A/1B With Susitna (Low Watana Non-Expandable Option)69,133,553 124,640 19,620 Forced 1A/1B With Susitna (Low Watana Expandable Option)Forced 69,133,553 124,640 19,620 1A/1B With Susitna (Low Watana Expansion Option)Forced 67,724,563 136,906 23,589 1A/1B With Susitna (Watana Option)Forced 70,966,059 111,307 19,171 1A/1B With Susitna (High Devil Canyon Option)Forced 71,853,368 121,538 19,909 1A/1B With Modular Nuclear 79,664,701 126,881 22,787 1A/1B With Tidal 75,598,948 121,306 21,067 1A/1B With Lower Coal Fuel and Lower Coal Capital Costs 80,259,047 124,215 21,768 1A/1B With Tax Credits for Renewables 74,046,352 129,384 18,832 Black &Veatch 1-18 February 2010 SECTION 1 EXECUTIVE SUMMARY 1.7.4 Results of Transmission Analysis ALASKA RIRP STUDY Table 1-6 lists the proposed transmission system expansions and enhancements that resulted from our transmission analysis.More detailed information on each of the identified transmission projects is provided in Section 12. Table 1-6 Summary of Proposed Transmission Projects Project No.Transmission Projects Type Cost ($000) A Bernice Lake -International New Build (230 kV)227,500 Soldotna -Quartz Creek R&R (230 kV)126,500 C Quartz Creek -University R&R (230 kV)165,000 D Douglas -Teeland R&R (230 kV)62,500 E Lake Lorraine -Douglas New Build (230 kV)80,000 F Douglas -Healy Upgrade (230 kV)30,000 G Douglas -Healy New Build (230 kV)252,000 H Ektutna -Fossil Creek Upgrade (230 kV)65,000 I Healy -Gold Hill R&R (230 kV)180,500 J Healy -Wilson Upgrade (230 kV)32,000 K Soldotna Diamond Ridge R&R (115 kV)66,000 L Lawing -Seward Upgrade (115 kV)15,450 M Eklutna -Lucas R&R(115 kV/230 kV)12,300 N Lucas -Teeland R&R (230 kV)51,100 O Fossil Creek -Plant 2 Upgrade (230 kV)13,650 P Pt.Mackenzie -Plant 2 R&R (230 kV)32,400 Q Bernice Lake -Soldotna Rebuild (115 kV)24,000 R Bernice Lake Beaver Creek -Soldotna |Rebuild (115 kV)24,000 S Susitna Transmission Additions New Build (230 kV)57,000 Black &Veatch 1-19 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY A diagram that shows the location of the proposed transmission system enhancements is shown in Figure 1-7. This graphic shows the proposed transmission projects if the Susitna hydroelectric project is not developed.A similar graphic of proposed transmission projects if Susitna is built is provided in Section 12. Figure 1-7 Location of Proposed Transmission Projects (Without Susitna) Enel EALY 250 KW >U 2 --o.'=| 7 E 239 kV [al DOUGLAS Tao kv TERMI 24,iJUm ©&"A Eaves EAVESTX 9G Sot?Dav CO sa WDRO 2025 KE Z30 eV The following issues result from our transmission analysis: e We were unable to complete a stability analysis based upon our proposed transmission system configuration prior to the completion of this project.This analysis is required to ensure that the proposed transmission system expansions and enhancements result in the necessary stability to ensure reliable electric service over the planning horizon.This analysis should be completed as part of the future work to further define,prioritize,and design specific transmission projects. Black &Veatch 1-20 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY e In addition to the transmission lines listed above,other projects were considered that could contribute to improving the reliability of the Railbelt system.These projects generally fall into one or more of the following categories: ec Providing reactive power (static var compensators -SVCs) o Providing or assisting with the provision of other ancillary services (regulation and/or spinning reserves) o Assistance in control of line flows or substation voltages o Assistance in the transition and coordination of transmission project implementation (mobile transforms or substations) o Communications and control facilities Several of these projects have been identified and discussed while others will result from the transmission reliability assessment.Potential projects in this category include: o Substation capacitor banks Series capacitors SVCs Battery energy storage systems (BESS) Mobile substations that could provide construction flexibility during the implementation phase e Projects that could facilitate or complement the implementation of other projects (e.g.,wind),were of particular interest during project discussions.These projects,if implemented,could smooth the transition and adoption by the utilities of the GRETC concept.One such project was the BESS that could provide much needed frequency regulation and potentially some spinning reserves when non-dispatchable projects,such as wind,are considered.A BESS was specified that could provide frequency regulation required by the system when wind projects were selected by the RIRP.The BESS was sized in relation to the size of the non-dispatchable project to be 50 percent of the project nominal capacity for a 20-minute duration.Although the performance of the BESS has not yet been analyzed as part of the stability analysis,the costs for each such system were included in the analysis. Other options (e.g.,fly wheel storage technologies and compressed air energy storage)that could provide the required frequency regulation should also be considered. e It should be noted that if the need for frequency regulation is driven in part by an IPP-sponsored renewable project,policies will need to be adopted to allocate an appropriate portion of the regulation costs to those projects. e The Fire Island Wind Project is a54 MW maximum output wind project.Each wind turbine will be equipped with reactive power and voltage support capabilities that should facilitate interconnection into the transmission grid.Current plans are to interconnect the project to the grid via a 34.5 kV underground and submarine cable to the Chugach 34.5 kV Raspberry Substation.There has been some discussions regarding the most appropriate transmission interconnection for the Fire Island Project and detailed interconnection studies have not been completed.The timeframe for implementing this project in order to qualify for available grants under the American Recovery and Reinvestment Act of 2009 (ARRA)could preclude more detailed transmission studies and consideration of alternatives to the currently proposed 34.5 kV interconnection.An option to consider if Fire Island is constructed is to lay cables from Fire Island to Anchorage insulated for 230 kV and reviewa transmission routing for the new transmission connection to the Kenai peninsula that would begin at the International 230 kV Substation to Bernice Lake Substation along the Kenai cost line then via submarine cable across the Cook Inlet to Fire Island.The interconnection would then use the 230 kV submarine cable previously laid over to the Anchorage coast then into the International 230 kV Substation.0000Black &Veatch 1-21 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY e The recommended transmission system expansions and enhancements can not be justified based solely on economics.However,in addition to their underlying economics,these transmission projects are required to ensure the reliable delivery of electricity throughout the region over the 50-year planning horizon and to provide the foundation for future economic development efforts. The proposed projects identified in Section 12 are not presented in any specific order or priority.It was felt that the information currently available,as well as the uncertainty which exists surrounding the selected generation plans,did not permit a more definitive prioritization of projects.This does not mean,however,that all the projects in the list have the same impact on the reliability of the Railbelt system,or that the projects are equally important to each utility.In several instances the projects were in extremely poor physical condition and were scheduled to be repaired or rebuilt to prevent the lines from literally falling to the ground.To facilitate the immediate repairs to these lines,the projects that should be addressed within the next five years because of their potential impact on the reliability of the system have been identified.Additionally,some of the projects will need to be evaluated and specified further and funds have been identified to facilitate the studies that are required to further identify and schedule the transmission improvements that will be required. The following projects and studies have been identified for priority attention (i.e.,to be completed within the next five years)because of their immediate impact on the reliability of the existing system.All of the projects will require detailed system feasibility studies prior to actual implementation. Soldotna to Quartz Creek Transmission Line ($126.5 million -Project B) Quartz Creek to University Transmission Line ($165.0 million -Project C) Douglas to Teeland Transmission Line ($62.5 million -Project D) Lake Lorraine to Douglas Transmission Line ($80.0 million -Project E) SVCs ($25.0 million -Other Reliability Projects) Funds to undertake the study of the Southern Intertie ($1.0 million) Funds to investigate the provision of regulation that will facilitate the integration of renewable energy projects into the Railbelt system ($50.0 million,including cost of BESS -Other Reliability Projects)NOOOBwnrThe total estimate costs necessary for transmission projects during the initial five years of the RIRP is $510 million in 2009 dollars. 1.7.5 Results of Financial Analysis It will be difficult for the region to obtain the necessary financing for the DSM/EE,generation and transmission resources included in the alternative resource plans that were developed.The formation of a regional entity with some form of State assistance will help meet this challenge. Figure 1-8 summarizes the cumulative capital investment required for each of the four base cases. Black &Veatch 1-22 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-8 Required Cumulative Capital Investment for Each Base Case Cumulative Capital Investment $20,000,000 : &$18,000,000 --Scenario 1A/1B -_ --Scenario 2A f$16,000,000 .--Scenario 2B yA$14,000,000 [oo$12,000,000 $10,000,000 [L $8,000,000 YA -- $6,000,000 [V $4,000,000 LZ$2,000,000 ACumulativeCapitalInvestment($000-Oo WO OO --OMY Oo --Owner OW Ke OMOnE™ DO Ke OM wYner ODrTrrrFTNNNNNYSDOHUmOLUmUNMYCUcUNMCUTYTLCTrhUCUTTrlCUCUCUMhUhTMUhHOHMHYHYLHeoocloOmUCUOCCUUCUCUOCCUOCUCUOCCUKUKUCUCCcUWCCUKUOUCUCUBUUCUWCCUKUCUCCUCUCUCUCUOCUCUOCUCUOCUCUlUCKlUcCSNlUCSNNNNNNNNNNNNNNNNNNNNNNNANON Year To assist in the completion of the financial analysis,AEA contracted with SNW to: e Provide a high-level analysis of the capital funding capacity of each of the Railbelt utilities. e Analyze strategies to capitalize selected RIRP assets by integrating State (which could include loans, State appropriations,Permanent Fund,State moral obligation bonds,etc.)and federal (e.g.,USDA-RUS)financing resources with debt capital market resources. e Develop a spreadsheet model that utilizes inputs from this RIRP analysis and overlays realistic debtcapitalfundingtoprovideatotalcosttoratepayersoftheoptimalresourceplan. The results of the financial analysis completed by SNW are provided in Appendix B. Important conclusions from SNW's report include: e The scope of the RIRP projects is too great,and for certain individual projects,it is reasonable to conclude that there is no ability for a municipality or cooperative utility to independently secure debt financing without committing substantial amounts of equity of cash reserves. e Figure 1-9 helps to put into context the scope of the required RIRP capital investments relative to the estimated combined debt capacity of the Railbelt utilities.The lines toward the bottom of the graph represent SNW's estimate of the bracketed range of additional debt capacity collectively for the Railbelt utilities,adjusted for inflation and customer growth over time. Black &Veatch 1-23 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-9 Required Cumulative Capital Investment (Scenarios 1A/1B)Relative to Railbelt Utility Debt Capacity $10,000,000,000 Capital Expenditures r 4 $7,500,000,000 $5,000,000,000 -High Debt Capacity $2,500,000,000 $0 TETTTTTTETPTTrTrrryrrrrrrr rrr rr et rrr rT PTT rr rar arr Oo MVD AN HY)OB St FThHr SOMO AD oo oo cl.lUcr;WclchcOUUlclUlUc rlUlUCc UUlCUCcCURUlUCUCUOUlLUCUOUCUCUCUOULUCUCUOCUCOULUCOOUlUO CEA A A AN AN ANN NN AN ANN NON AW Source:SNW Report included in Appendix C. e A regional entity,such as GRETC,with "all outputs”contracts migrating over time to "allrequirements”contracts will have greater access to capital than the combined capital capacity of the individual utilities. e There are several strategies that could be employed to lower the RIRP-related capital costs to customers,including: [e) °o Ratepayer Benefits Charge -A charge levied on all ratepayers within the Railbelt system that would be used to cash fund and thereby defer borrowing for infrastructure capital. "Pay-Go”Versus Borrowing for Capital -A pay-go financing structure minimizes the total cost of projects through the reduction in interest costs.A "pay-go”capital financing program is one in which ongoing capital projects are paid for from remaining revenue after operations and maintenance (O&M)expenses and debt service are paid for.A balance of these two funding approaches appears to be the most effective in lowering the overall cost of the RIRP,as well as spreading out the costs over a longer period of time. Construction Work in Progress (CWIP)-CWIP is a rate methodology that allows for the recovery of interest expense on project construction expenditures through the base rate during construction,rather than capitalizing the interest until the projects are on-line and generating power.It should be noted that this rate methodology is sometimes criticized for shifting risks for shareholders to ratepayers;however,in the case of a public cooperative or municipal utility,the "shareholders”are the ratepayers. Black &Veatch 1-24 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY o State Financial Assistance -State financial assistance could take a variety of forms as previously noted;for the purposes of this project,SNW focused on State assistance structured similarly to the Bradley Lake project.The benefits of State funding include:repayment flexibility,credit support/risk mitigation,and potential interest cost benefit. It should be noted that the economic comparison of resource options (using Strategist™and PROMOD™)does not assume any of these financing strategies,including any State grants of Federal tax credits,with the exception of the Federal Tax Credits for Renewables Sensitivity Case. e The overall objective of SNW's analysis was to identify ways to overcome the funding challenges inherent with large-scale projects,including the length of construction time before the project is online and access to capital markets,and to develop strategies that could be used to produce equitable rates over the useful life of the assets being financed.With these challenges in mind,SNW developed separate versions of its model to capture the cost of financing under a "base case”scenario and an "alternative”scenario.The base case financing model was structured such that the list of RIRP projects during the first 20 years would be financed through the capital markets in advance of construction and that the cost of the financing in the form of debt service on the bonds would immediately be passed through to the ratepayers;the projects being financed over the balance of the 50-year period would be financed through cash flow created through normal rates and charges ("pay-go”),once debt service coverage from previous years has grown to levels that create cash flow balance amounts sufficient to pay for the projects as their construction costs come due.The alternative model was developed with the goal of minimizing the rate shock that may otherwise occur with such a large capital plan,and levelizing the rate over time so that the economic burden derivedfromtheseprojectscanbespreadmoreequitablyovertheusefullifeoftheprojectsbeing contemplated. e In both the base and alternative cases,SNW transferred the excess operating cash flow that is generated to create the debt service coverage level,and using that balance to both partially fund the capital projects in the early years and almost fully fund the projects in the later years.In the alternative case,SNW also included:1)a Capital Benefits Surcharge ($0.01 per kWH)over the first 17 years,when approximately 75 percent of the capital projects will have been constructed,and 2)State assistance as an equity participant,structured in a manner similar to the Bradley Lake financing model (SNW assumed that the State would provide a $2.4 billion zero-interest loan to GRETC to provide the upfront funding for the Chakachamna project,only to be paid back by GRETC out of system revenues over an extended period of time,and following the repayment of the potentially more expensive capital market debt). e Under the base case,the maximum fixed charge rate on the capital portion aloneis estimated to cost $0.13 per kWH,while theaverage fixed charge rate over the 50-year periodis $0.07 per kWh. e Inthe alternative case,the maximum fixed charge rate on the capital portion aloneis estimated to cost $0.08 per kWH,while theaverage fixed charge rate over the 50-year periodis $0.06 per kWh,not including the $0.01 consumer benefit surcharge thatis in place for the first 17 years. e While the average rates between the two cases are essentially the same,the maximum rate in the alternative case is much lower,showing the ability of innovative financing tools and ratemaking methodologies to overcome the funding challenges and provide equitable rates over the 50-year period. Black &Veatch 1-25 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY e The formation of a regional entity,such as GRETC,that would combine the existing resources and rate base of the Railbelt utilities,as well as provide an organized front in working to obtain private financing and the necessary levels of State assistance,would be,in SNW's opinion,a necessary next step towards achieving the goal of reliable energy for the Railbelt region now and in the future. 1.8 Implementation Risks and Issues There are a number of general risks and issues that must be addressed regardless of the resource future that is chosen by stakeholders,including the utilities and State policy makers.Additionally,each alternative DSM/EE,generation and transmission resource type has its own specific risks and issues.Section 14 includes a detailed discussion of these general and resource-specific implementation-related risks and issues. A Note Regarding Risks e Risk is an inherent element of any long-term integrated resource plan.This RIRP is not different. e Risks associated with fuel supply,project development,operations,environmental,transmission, regulatory,and so forth,all affect the region's optimal future resource path.These risks are identified and discussed in this report. e Inmany ways,this RIRP is the beginning of a journey;hard work is required to address these risks and make the difficult policy choices necessary to secure a reliable energy future. 7.8.1.General Risks and Issues General issues and risks related to the implementation of the RIRP include the following: e Organizational,including: o The lack of a regional entity with the responsibility for implementing the RIRP will lead to suboptimal solutions,resulting in higher costs,lower reliability and the inability to manage the successful integration of DSM/EE and renewable resources into the Railbelt system. o To date,the Railbelt utilities have not been able to take full advantage of economies of scale for several reasons.Absent taking a regional approach to future resource planning and development, this reality will continue. o Fuel supply risks,including the future deliverability and price of natural gas. o Risks resulting from the inadequacy of the current regional transmission network. o Market development risks and issues,including the need to implement a competitive power procurement process to encourage the development of generation projects by IPPs,and the potential for large load increases. o Financing and rate issues,related to the ability of the region to finance the capital investments identified in the RIRP and the need to mitigate the rate impact of those investments. o Legislative and regulatory issues,including the potential impact that a State Energy Plan and the passage of energy-related policies could have on the RIRP. Black &Veatch 1-26 February 2010 SECTION 1 EXECUTIVE SUMMARY 7.8.2 Resource Specific Risks and Issues Table 1-7 provides Black &Veatch's assessment of the relative magnitude of various categories of risks and issues for each resource type,including: Resource Potential Risks -the risk associated with the total energy and capacity that could be economically developed for each resource option. Project Development and Operational Risks -the risks and issues associated with the development of specific projects,including regulatory and permitting issues,the potential for construction costs overruns, actual operational performance relative to planned performance,and so forth.This category also includes non-completion risks once a project gets started,the risk that adverse operating conditions will severely damage the facilities resulting in a shorter useful life than expected,and project delay risks. Fuel Supply Risks -the risks and issues associated with the adequacy and pricing of required fuel supplies. Environmental Risks -the risks of environmental- related operational concerns and the potential for future changes in environmental regulations. Transmission Constraint Risks -the risk that the ability to move power from a specific generation resource to where that power is needed will be inadequate,an issue that is particularly important for large generation projects and remote renewable projects. Financing Risks -the risk that a regional entity or individual utility will not be able to obtain the financing required for specific resource options under reasonable and affordable terms and conditions. Regulatory/Legislative Risks -the risk that regulatory ALASKA RIRP STUDY Fundamental RIRP-Related Risks and Uncertainties General +Regional implementation of RIRP elements *Financial capability of Railbett utilities DSM/Energy Efficiency (DSM/EE) *Lack of Alaska-specific information *Total achievable resource potential +Long-term reliability of savings *Funding source Generation Resources -Conventional +Natural gas supplies,deliverability and prices +Future emissions regulations (including CO,) Generation Resources Renewables *Total economic resource potential *Optimization of potential sites +Project completion risks associated with large hydro and tidal +Integration of non-dispatchable resources +Environmental and permitting issues Transmission +Adequacy of backbone grid to move power and ensure reliability +Generation site-specific interconnections *Siting and permitting issues and legislative issues could affect the economic feasibility of specific resource options. Price Stability Risks -the risk that wholesale power costs will increase significantly as a result of changes in fuel prices and other factors (e.g.,COz costs). Black &Veatch 1-27 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-7 Resource Specific Risks and Issues -Summary Relative Magnitude of Risk/Issue Project Resource Development Transmission Regulatory/Potential and Operational |Fuel Supply Environmental Constraint Legislative |Price StabilityResourceRisksRisksRisksRisksRisksFinancingRisksRisksRisks DSM/EE Moderate Limited N/A N/A N/A Limited -Moderate Limited Moderate Generation Resources Natural Gas Limited Limited Significant Moderate Limited Moderate Moderate Significant Coal Limited Moderate-Limited Moderate -Limited -Moderate -Moderate Moderate Significant Significant Significant Significant Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Significant Large Hydro Limited Significant Limited Significant Significant Significant Significant Limited Small Hydro Moderate Moderate Limited Moderate Moderate Limited -Limited Limited Moderate Wind Moderate Moderate N/A Limited Moderate Limited -Limited Limited - Moderate Moderate Geothermal Moderate Limited -N/A Limited -Moderate -Limited -Limited Limited Moderate Moderate Significant Moderate Solid Waste Limited Moderate-N/A Significant Moderate Limited -Limited-Moderate Significant Moderate Moderate Tidal Limited Significant N/A Significant Moderate -Moderate -Moderate -Limited - Significant Significant Significant Moderate Transmission Limited Significant N/A Moderate N/A Significant Moderate -N/A Significant Black &Veatch 1-28 February 2010 SECTION 1 EXECUTIVE SUMMARY 1.9 1.9.1 ALASKA RIRP STUDY Conclusions and Recommendations Conclusions The primary conclusions from the RIRP study are discussed below. 1.The current situation facing the Railbelt utilities includes a number of challenging issues that place the region at a historical crossroad regarding the mix of DSM/EE,generation,and transmission resources that it will rely on to economically and reliably meet the future electric needs of theregion's citizens and businesses.As a result of these issues,the Railbelt utilities are faced with thefollowingchallenges:o A transmission network that is isolated and has limited total transfer capabilities and redundancies. The inability of the region to take full advantage of economies of scale due to its limited size. A heavy dependence on natural gas from the Cook Inlet for electric generation. Limited and declining Cook Inlet gas deliverability. Lack of natural gas storage capability. The region's aging generation and transmission infrastructure.A heavy reliance on older,inefficient natural gas generation assets.The region's limited financing capability,both individually and collectively among the Railbelt utilities. o Duplicative and diffused generation and transmission expertise among the Railbelt utilities.0o0o000ag0000The key factors that drive the results of Black &Veatch's analysis include the following: o Therisks and uncertainties that exist for all alternative DSM/EE,generation,and transmission resource options. o The future availability and price of natural gas. ©The public acceptability and ability to permit a large hydroelectric project which is a greater concern,based upon Black &Veatch's discussions with numerous stakeholders,than the acceptability and ability to permit other types of renewable projects,such as wind and geothermal. o Potential future CO prices,which would impact all fossil fuels,that may or may not result from proposed Federal legislation. o The region's existing transmission network,which limits:1)the ability to transfer power between areas within the region to minimize power costs,and 2)places a maximum limit on the amount of non-dispatchable resources that can be integrated into the region's transmission grid. o The ability of the region to raise the required financing,either by the utilities on their own or through a regional G&T entity. o Whether the Railbelt utilities develop a number of currently proposed projects that were selected outside of a regional planning process. Figures 1-10 and 1-11 graphically demonstrate how the results of the various reference and sensitivity cases are impacted by these important uncertainties.Figure 1-10 shows the cumulative present value cost for each year over the 50-year planning horizon;similarly,Figure 1-11 shows the annual wholesale power cost (cents/kWh)in 2010 dollars.In both cases,we have shown selected reference and sensitivity cases to highlight how dependent the results are to these key uncertainties. Black &Veatch 1-29 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-10 Cumulative Present Value Cost -Selected Reference and Sensitivity Cases CumulativePresentValueCost($000)Plan 1A/1B -1A/1B With Double DSM/EE Programs --1A/1B Without DSM/EE Programs --1A/1B With High Gas Prices --1A/1B Without CO2 Taxes ---1A/1B Without Chakachamna -----1A/1B With Susitna (Low Watana Expansion)---1A/1B With Committed Units Figure 1-11 Annual Wholesale Power Cost -Selected Reference and Sensitivity Cases 25.00 20.00 WholesalePowerCost(cents/kWh)-2010Dollars5.00 0.00 sen en BaeODDeee Nm OD WN 2D AWN nd WN OD oN nd 2 A Sa NN »©NW OO AN ®©A QSNUNSNOYShYQPBEFSD”6?OD?OO OOCEPPPKKKKKKKKKKSOSEKKKKLKO Year --Plan 1A/1B --Plan2A -1A/1B With Double DSM/EE Programs --1A/1B Without DSWEE Programs --1A/1B With High Gas Prices --1A/1B Without CO2 Taxes --1A/1B Without Chakachamna --1A/1B With Susitna (Low Watana Expansion) --1A/1B With Committed Units Black &Veatch 1-30 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY As can be seen in Figure 1-10,which shows cumulative net present value costs over the 50-year planning horizon,the 1A/1B With Susitna (Low Watana Expansion),1A/1B With no DSM/EE Programs,1A/1B Without Chakachamna,1A/1BWith Committed Units,and 1A/1B With High Gas Prices Sensitivity Cases are all higher cost than Scenario 1A/1B,in descending order.The 1A/1B With Double DSM/EE Programs and 1A/1B With No CO;Taxes Sensitivity Cases are lower cost that Scenario 1A/1B. Figure 1-11 shows how significant the uncertainty regarding CO;taxes is with regard to the results. It also shows the economic value of achieving higher DSM/EE savings that were assumed in the Scenario 1A/1B Reference Case if those savings can be achieved.Also,shown is the fact that the other sensitivity cases are higher cost than Scenario 1A/1B. 3.The resource plans that were developed as part of this study for each Evaluation Scenario include a diverse portfolio of resources.If implemented,the RIRP will lead to: o The development of a resource mix resulting from a regional planning process. Greater reliance on DSM/EE and renewable resources and a lower dependence on natural gas. A more robust transmission network. More effective spreading of risks among all areas of the region. A greater ability to respond to large load growth should these load increases occur.Statedanotherway,the implementation of the RIRP will provide a stronger foundation upon which to base future economic development efforts.00004.The cost of this greater reliance on DSM/EE and renewable resources is less than the continued heavy reliance on natural gas based upon the base case gas price forecast that was used in this analysis.This result is achievable if the region builds a large hydroelectric project.There are uncertainties,at this point in time,regarding the environmental and/or geotechnical conditions under which a large hydroelectric project could be built.If a large hydroelectric facility can not be developed,or if the cost of the large hydroelectric project significantly exceeds the current preliminary estimates,then the costs associated with a predominately renewable future would be greater than continuing to rely on natural gas. 5.Our analysis shows that Scenarios 1A and 1B result in the same resources and,consequently,the same costs and emissions.In other words,the cost of achieving a renewable energy target of 50 percent by 2025 (Scenario 1B)is no greater than the cost of the unconstrained solution (Scenario 1A).This result applies only if a large hydroelectric project is built. 6.Scenarios 2A and 2B were evaluated to determine what the impact would be if the demand in the region was significantly greater than it is today.In fact,the per unit power costs were not less than Scenario 1A/1B due to the cost of Susitna which was the resource chosen to meet this additional load. 7.Additionally,the implementation of a regional plan will result in lower costs than if the individual Railbelt utilities continue to go forward on their own.While the scope of this study did not include the development of separate integrated resource plans for each of the six Railbelt utilities,we did complete a sensitivity analysis to show the cost impact if the utilities develop their currently proposed projects (referred to as committed units)that were selected outside of a regional planning process. The Railbelt utilities are moving forward with these projects due to the existing uncertainty regarding the formation of GRETC.While this sensitivity case does not fully capture the incremental cost of the utilities acting independently over the 50-year planning horizon,it does provide an indication of the relative cost differential.Figure 1-12 shows the resulting total annual costs of the two different resource plans.In the aggregate,the cost of the Committed Unit Sensitivity Case was approximately Black &Veatch 1-31 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 5.6 percent,or $484 million on a cumulative net present value cost basis,higher than Scenario 1A/1B. The main conclusion to draw from this graphic is that there are significant cost savings associated with the Railbelt utilities implementing a plan that has been developed to minimize total regional costs,while ensuring reliable service,as opposed to the individual utilities working separately to meet the needs of their own customers. Figure 1-12 Comparison of Results -Scenario 1A/1B Versus Committed Units Sensitivity Case CumulativePresentValueCost($000)Sdr*)a a a ee ale ee [Plan 1A/1B - 1A/1B With Committed Units| 8.There are a number of risks and uncertainties regardless of the resource options chosen.For example: 1)there is a lack of Alaska-specific data upon which to build an aggressive region-wide DSM/EE program,2)the future availability and price of natural gas affects the viability of natural gas generation,and 3)the total economic potential of various renewable resources is unknown at this time.In some cases,these risks and uncertainties (e.g.,the ability to permit a large hydroelectric facility)might completely eliminate a particular resource option.Due to these risks and uncertainties, it will be important for the region to maintain flexibility so that changes to the preferred resource plan can be made,as necessary,as these resource-specific risks and uncertainties become more clear or get resolved. 9.Significant investments in the region's transmission network need to be made within the next 10 years to ensure the reliable and economic transfer of power throughout the region.Without these investments,providing economic and reliable electric service will be a greater challenge. 10.The increased reliance on non-dispatchable renewable resources (e.g.,wind)will require a higher level of frequency regulation within the region to handle swings in electric output from these resources.An increased level of regulation has been included in Black &Veatch's transmission plan. Even with this increased regulation,however,the challenges associated with the integration of non- dispatchable resources will ultimately place a maximum limit on the amount of these resources that can be developed. Black &Veatch 1-32 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 11.The implementation of the RIRP does not require that a regional generation and transmission entity (e.g.,GRETC)be formed.However,the absence of a regional entity with the responsibility for implementing the RIRP will increase the difficulty of the region's ability to implement a regional plan and,in fact,Black &Veatch believes that the lack of a regional entity will,as a practical matter,mean that the RIRP will not be fully implemented.As a consequence,the favorable outcomes of the RIRP discussed above would not be realized.The interplay between the formation of a regional entity and the RIRP is shown in Figure 1-13. Figure 1-13 Interplay Between GRETC and Regional Integrated Resource Plan Current RIRP Study REGA Study |Situation *Plan that economically ani schedules what,when,*Limited redundancy and where to build,based . +Limited economies on available fuet and .: of scale energy supplies Proposed Future Situation +Dependence on +50-year time horizon RIRP GRETC +Robust transmission fossil fuels +Competes generation,Results Formation +Diversified fuel supply *Limited Cook Inlet transmission,fuel supply «Increased +System-wide power ratesgasdeliverabilityandDSM/energy DSM/energy | and storage efficiency options.efficiency ,+Spread risk +Aging G&T *Considers CO,regulation «Increased '+State financial assistance infraswucture ome Includes renewable [-|renewables GRETC -Enabler +Regional planning +Inefficient fuel use energy projects *Reduced +Wise resource use +Difficult financing +Amives at a pian to build dependence t to large toad +Duplicative Gat future infrastructure for On natural gas 7 7 7 growthexPriseminimumtong-run cost to +Increased inancin tion .P ratepayers transmission ;5 *Technical resources *Pre-funding of capital . +Considers fuel supply requiements +New technologies options and risks +Commercial bond market +State financial assistance (Bradtey Lake model) »Construction-work-in-progress 10-Year Transition Period 1.9.2 Recommendations This subsection summarizes the overall recommendations arising from this study,broken down into the following three categories: e Recommendations -General e Recommendations -Capital Projects e Recommendations -Other 1.9.2.1 Recommendations -General The following general actions should be taken to ensure the timely implementation of the RIRP: 1.The State should work closely with the utilities and other stakeholders to make a decision regardingtheformationofGRETCandtodeveloptherequiredgovernanceplan,financial and capital improvement plan,capital management plan and transmission access plan,and address other matters related to the formation of the proposed regional entity. Black &Veatch 1-33 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 2.The State should establish certain energy-related policies,including: o The pursuit of large hydroelectric facilities o DSM/EE program targets o RPS (ie.,target for renewable resources),and the pursuit of wind,geothermal,and tidal (which will become commercially mature during the 50-year planning horizon)projects in addition to large hydroelectric projects;the passage of an RPS would be meaningful as a policy statement even though the preferred resource plan would achieve a 50 percent renewable level by 2025. o System benefit charge to fund DSM/EE programs and or renewable projects 3.The State should work closely with the Railbelt utilities and other stakeholders to establish the specific preferred resource plan.In establishing the preferred resource plan,the economic results of the various reference cases and sensitivity cases evaluated in this study should be considered,as well as the environmental impacts discussed in Section 13 and the project-specific risks discussed in Section 14. 4.Black &Veatch believes that the Scenario 1A/1B resource plan should be the starting point for the selection of the preferred resource plan as discussed below.Table 1-8 provides a summary of the specific resources that were selected,based upon economics,in the Scenario 1A/1B resource plan during the first 10 years. A project selected in Scenario 1A/1B after the first 10 years especially worthy of mention is theChakachamnaHydroelectricProjectin2025. Another important consideration in the selection of a preferred resource plan is evaluation of the sensitivity cases evaluated,as presented in Section 13.Issues addressed through the sensitivity cases and considered in Black &Veatch's selection of a preferred resource plan include the following and are discussed in Table 1-9.Following that discussion, o What if CO;regulation doesn't occur? o What is the effect if the committed units are installed? o What if Chakachamna doesn't get developed? o What would be the impact of the alternative Susitna projects? There are several projects that are significantly under development and included in the preferred resource plan.These significantly developed projects include: o Healy Clean Coal Project (HCCP) o Southcentral Power Project o Fire Island Wind Project o Nikiski Wind Project These projects are discussed in Table 1-10. In addition to these resources,Black &Veatch believes that Mt.Spurr,Glacier Fork,Chakachamna and Susitna should be pursued further to the point that the uncertainties regarding the environmental, geotechnical and capital cost issues become adequately resolved to determine if any of the projects could actually be built. Black &Veatch 1-34 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-8 Resources Selected in Scenario 1A/1B Resource Plan Project Discussion DSM/EE Resources The full level of DSM/EE resources evaluated was selected based upon their relative economics.Sensitivity analysis indicates that even greater levels of DSM/EE may be cost-effective.The lack of Alaska-specific DSM/EE data causes the exact level of cost-effective DSM/EE to remain uncertain. Nikiski Wind The RIRP selected this project in the initial year.It is being developed as an IPP project and is well along in the development process.The ARRA potentially offers significant financial incentives if this project is completed by January 1,2013.These incentives could further improve its competitiveness.As a wind unit,it has no impact on planning reserves,but contributes to renewable generation. HCCP HCCP is completed and GVEA has negotiated with AIDEA for its purchase.This project was selected in the initial year of the plan. Fire Island Wind Project The Fire Island Wind Project is being developed as an IPP project with proposed power purchase agreements provided to the Railbelt utilities.The project may be able to benefit significantly from ARRA and the $25 million grant from the State for interconnection.This project was selected in 2012. Anchorage 1x1 6FA Combined Cycle The RIRP selected this unit for commercial operation in 2013.This unit is very similar in size and performance to the Southcentral Power Project being developed as a joint ownership project by Chugach and ML&P for 2013 commercial operation. The project appears well under development with the combustion turbines already under contract.The project fits well with the RIRP and the joint ownership at least partially reflects the GRETC joint development concept. Glacier Fork Hydroelectric Project The RIRP selected this project for commercial operation in 2014,the first year that it was available for commercial operation in the models.Of the large hydroelectric projects,Glacier Fork is by far the least developed.Glacier Fork has very limited storage and thus does not offer the system operating flexibility of the other large hydroelectric units.There is also significant uncertainty with respect to its capital cost and ability to be licensed.Because it has such a minimal level of firm generation in the winter,it does not contribute significantly to planning reserves,but does contribute about 6 percent of the renewable energy to the Railbelt.Detailed feasibility studies and licensing are required to advance this option. Anchorage and GVEA MSW Units The RIRP selected these units in 2015 and 2017.Historically,mass burn MSW units such as those modeled,have faced significant opposition due to emissions of mercury,dioxin,and other pollutants.Other technologies which result in lower emissions,such as plasma arc,are not commercially demonstrated.The units included in the RIRP are relatively small (26 MW in total)and are not required to be installed to meet planning reserve requirements,but their base load nature contributes nearly 4 percent of the renewable energy.Detailed feasibility studies would be required to advance this alternative. GVEA North Pole Retrofit The retrofitting of GVEA's North Pole combined cycle unit with a second train using a LM6000 combustion turbine and heat recovery steam generator was selected in 2018 coincident with the assumption of the availability of natural gas to GVEA.The retrofit takes advantage of capital and operating cost savings resulting from the existing installation. Black &Veatch 1-35 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-8 (Continued) Resources Selected in Scenario 1A/1B Resource Plan Project Discussion Mt.Spurr Geothermal Project The first unit at Mt.Spurr was selected in 2020.Mt.Spurr's developer,Ormat, currently has commercial operation scheduled for 2017.Significant development activity remains for the project including verifying the geothermal resource.Mt. Spurr will also require significant infrastructure development including access roads and transmission lines.This infrastructure may correspond to similar infrastructure development required for Chakachamna which is selected in 2025 in the RIRP.As the implementation of the RIRP unfolds,there will likely be the need to adjust the timing of the resource additions following the implementation of the initial projects. Table 1-9 Impact of Selected Issues on the Preferred Resource Plan Issue Discussion CO,Regulation The sensitivity case for Scenario 1A without CO,regulation selects the Anchorage LMS 100 project instead of Fire Island and Mt.Spurr in the first 10 years. Committed Units Installation of the committed units significantly increases the cost of Scenario 1A/1B.In addition to the committed units,this plan selects five wind units from 2016 through 2024 in response to COz regulation.The plan with the committed units eliminates Chakachamna and does not meet the 50 percent renewable target by 2025. Chakachamna Chakachamna could fail to develop because of licensing or technical issues.Also,if the cost of Chakachamna were to increase to be equivalent to the alternative Susitna projects on a GWh basis,it would not be selected.The sensitivity case without Chakachamna for the first 10 years is identical to Scenario 1A/1B.The case does not meet the 50 percent renewable target by 2025 and is 5.2 percent higher in cost than the preferred resource plan. Susitna None of the alternative Susitna projects are selected in the Scenario 1A/1B resource plan.The least cost Susitna option,which is Low Watana Expansion,is 15.3 percent more than the preferred resource plan and 9.0 percent more than the case without Chakachamna.The 50 percent renewable requirement can not be met without Susitna if Chakachamna is not available. Black &Veatch 1-36 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-10 Projects Significantly Under Development Project Discussion Preferred Resource Plan Recommendation HCCP HCCP is completed and GVEA has negotiated with |Black &Veatch recommends that HCCP beAIDEAforitspurchase.The project is part of the |included in the preferred resource plan.least cost scenario.While CO;regulation has been assumed in the RIRP,those regulations are not in place and there is no absolute assurance that they will be in place or what the costs from the regulations will be.HCCP adds further fuel diversity to the Railbelt,especially to GVEA who doesn't currently have access to natural gas.Asa steam unit,HCCP improves transmission system stability. Southcentral The Southcentral Power Project is well under Black &Veatch recommends the continued Power Project |development with the combustion turbines development of the Southcentral Power Project purchased.The timing and technology are as part of the preferred resource plan. generally consistent with the preferred resource plan.The project will improve the efficiency of natural gas generation in the Railbelt and permit the retirement of aging units. Fire Island The Fire Island Wind Project is being developed as_|Subject to the successful negotiation of aWindProject|an IPP project with proposed power purchase purchase power agreement and successful agreements provided to the Railbelt utilities.The negotiation of the interconnection and project may be able to benefit significantly from regulation issues,Black &Veatch recommendsARRAandthe$25 million grant from the State for |that it be part of the preferred resource plan in ainterconnection.This project is part of the least time frame that allows for the ARRA benefits cost plan and provides renewable energy to the to be captured. Railbelt system.Issues with interconnection and regulation will need to be resolved. Nikiski Wind |The Nikiski Wind Project is an IPP project like Fire |Like Fire Island,subject to successfulProjectIslandandhasthesamepotentialtobenefitfromnegotiationofapurchasepoweragreement and ARRA.It is also part of the least cost plan.successful negotiation of the interconnection and regulation issues,Black &Veatch recommends that it be part of the preferred resource plan in a time frame that allows for the ARRA benefits to be captured. Black &Veatch 1-37 February 2010 SECTION 1 EXECUTIVE SUMMARY 5. 7. ALASKA RIRP STUDY In the case of the Mt.Spurr Geothermal Project,exploration should continue to determine the extent and characteristics of the geothermal resource at the site. In the case of Susitna,the primary focus should be on completing engineering studies to optimize the size and minimize the costs of the project.In the case of Glacier Fork and Chakachamna,the additional work should look for "fatal flaws”. Additionally,further analysis needs to be completed relative to integrating wind and other non- dispatchable renewable resources into the transmission network. The State and Railbelt utilities should develop a public outreach program to inform the general public regarding the preferred resource plan,including the costs and benefits. The State Legislature should make decisions regarding the level and form of State financial assistance that will be provided to assist the Railbelt utilities and AEA,under a unified regional G&T entity (i.e,GRETC),develop the generation resources and transmission projects identified in the preferred resource plan. The electric utilities,various State agencies,Enstar and Cook Inlet producers need to work more closely together to address short-term and long-term gas supply issues.Specific actions that should be taken include: o Development of local gas storage capabilities with open access among all market participants as soon as possible. o Undertake efforts to secure near-term LNG supplies to ensure adequate gas over the 10-year transition period until additional gas supplies can be secured either in the Cook Inlet,from the North Slope or from long-term LNG supplies. o The State should complete a detailed cost and risk evaluation of available long-term gas supply options to determine the best options.Once the most attractive long-term supplies of natural gas have been identified,detailed engineering studies and permitting activities should be undertaken to secure these resources. o Appropriate commercial terms and pricing structures should be established through State and regulatory actions to provide producers with the incentive to increase exploration for additional gas supplies in the Cook Inlet or nearby basins.This action is required to provide the necessary long-term contractual certainty to result in additional exploration and development. 1.9.2.2 Recommendations -Capital Projects Efforts should be undertaken to begin the development,including detailed engineering and permitting activities,of the following capital projects,which are included in Black &Veatch's recommended preferred resource plan. 1. 2. Develop a comprehensive region-wide portfolio of DSM/EE programs. Generation projects: o Projects under development (HCCP,Southcentral Power Project,Fire Island Wind Project,and Nikiski Wind Project) Glacier Fork Hydroelectric Project Generic Anchorage MSW Project Generic GVEA MSW Project GVEA North Pole Retrofit Project Mt.Spurr Geothermal Project Chakachamna Hydroelectric Project Susitna Hydroelectric Project0000000 Black &Veatch 1-38 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Transmission and related substation projects,including the following projects which have been identified for priority attention because of their immediate impact on the reliability of the existing system.These projects are estimated to be required within the next five years. Soldotna to Quartz Creek Transmission Line ($84 million -Project B) Quartz Creek to University Transmission Line ($112.5 million -Project C) Douglas to Teeland Transmission Line ($37.5 million -Project D) Lake Lorraine to Douglas Transmission Line ($80 million -Project E) SVCs ($25 million -Other Reliability Projects) Funds to undertake the study of the Southern Intertie ($1 million) Funds to investigate the provision of regulation that will facilitate the integration of renewable energy projects into the Railbelt system ($50 million,including cost of BESS -Other Reliability Projects)00000001.9.2.3 Recommendations -Other Other actions,related to the implementation of the RIRP,that should be undertaken include: 1.The State Legislature should appropriate funds for the initial stages of the development of a regional DSMLEE program,including 1)region-wide residential and commercial end-use saturation surveys, 2)residential and commercial customer attitudinal surveys,3)vendor surveys,4)comprehensive evaluation of economically achievable potential,and 5)detailed DSM/EE program design efforts. Develop a regional DSM/EE program measurement and evaluation protocol. If GRETC is not formed,some type of a regional entity should be formed to develop and deliver DSM/EE programs to residential and commercial customers throughout the Railbelt region,in close coordination with the Railbelt utilities. Likewise,if GRETC is not formed,some type of a regional entity should be formed to develop the renewable resources included in the preferred resource plan. Establish close coordination between the Railbelt electric utilities,Enstar and AHFC regarding the development and delivery of DSM/EE programs. Aggressively pursue available Federal funding for DSM/EE programs and renewable projects. Further development of tidal power should be encouraged due to its resource potential in the Railbelt region.Although this technology is not commercially available,in Black &Veatch's opinion,at this point in time,it has the potential to be economic within the planning horizon. The State and Railbelt utilities should work closely with resource agencies to identify environmental issues and permitting requirements related to large hydroelectric and tidal projects,and conduct the necessary studies to address these issues and requirements. Complete a regional economic potential assessment,including the identification of the most attractive sites,for all renewable resources included in the preferred resource plan. .Develop streamlined siting and permitting processes for transmission projects. 11. 12. Develop a regional frequency regulation strategy for non-dispatchable resources. Develop a regional competitive power procurement process and a standard power purchase agreement to provide IPPs an equal opportunity to submit qualified proposals to develop specific projects. Black &Veatch 1-39 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 13.Federal legislative and regulatory activities,including those related to emissions regulations,should be monitored closely and influenced to the degree possible. 14.Monitor the licensing progress of small modular nuclear units. 1.10 Near-Term Implementation Action Plan (2010-2012) The purpose of this subsection section is to identify our overall recommendations regarding the near-term implementation plan,covering the period from 2010 to 2012.Our recommended actions are grouped into the following categories: e General actions e Capital projects e Supporting studies and activities e Other actions In many ways,this near-term implementation plan shown in Tables 1-11 through 1-14 serves two objectives. First,it identifies that steps that should be taken during the next three years regardless of the alternative resource plan that is chosen as the preferred resource plan.Second,it is intended to maintain flexibility as the uncertainties and risks associated with each alternative resource plan become more clear and or resolved. Black &Veatch 1-40 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.10.1 General Actions Table 1-11 Near-Term Implementation Action Plan --General Actions Actions Category Description Timeline Est.Cost General Actions e The State should work closely with the utilities and other 2010 $6.8 million stakeholders to make a decision regarding the formation of GRETC and to develop the required governance plan, financial and capital improvement plan,capital management plan and transmission access plan,and address other matters related to the formation of the proposed regional entity e Establish State energy-related policies regarding:2010-2011 |$0.2 millionoThepursuitoflargehydroelectricfacilities o DSM/EE program targets o RPS (ie.,target for renewable resources),and the pursuit of wind,geothermal,and tidal projects o System benefit charge to fund DSM/EE programs and or renewable projects e The State should work closely with the Railbelt utilities 2010 Not and other stakeholders to establish the preferred resource applicable plan,using the Scenario 1A/1B resource plan as the starting point ¢Mt.Spurr,Glacier Fork,Chakachamna and Susitna should |2010-2011 To be be pursued further to the point that the uncertainties determined regarding the environmental,geotechnical and capital cost issues become adequately resolved to determine if any of these projects could actually be built e Develop a public outreach program to inform the public 2010-2011 |$0.1 millionregardingthepreferredresourceplan,including the costs and benefits e The State Legislature should make decisions regarding the |2010-2011 Not level and form of State financial assistance that will be applicable provided to assist the Railbelt utilities and AEA,under a unified regional G&T entity (ie,GRETC),develop the generation resources and transmission projects identified in the preferred resource plan Black &Veatch 1-41 February 2010 SECTION 1 EXECUTIVE SUMMARY Table 1-11 (Continued) Near-Term Implementation Action Plan --General Actions ALASKA RIRP STUDY Actions Category Description Timeline Est.Cost The electric utilities,various State agencies,Enstar and Cook Inlet producers need to work more closely together to address short-term and long-term gas supply issues; specific actions that should be taken include: oO [e) [e) Development of local gas storage capabilities as soon as possible Undertake efforts to secure near-term LNG supplies to ensure adequate gas over the 10-year transition period until additional gas supplies can be secured The State should complete a detailed cost and risk evaluation of available long-term gas supply options to determine the best options;once the most attractive long-term supplies of natural gas have been identified, detailed engineering studies and permitting activities should be undertaken to secure these resources Appropriate commercial terms and pricing structures should be established through State and regulatory actions to provide producers with the incentive to increase exploration for additional gas supplies in the Cook Inlet or nearby basins 2010-2012 Tobe determined Black &Veatch 1-42 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.10.2 Capital Projects Table 1-12 Near-Term Implementation Action Plan -Capital Projects Actions Category Description Timeline Est.Cost Capital Projects e Develop a comprehensive region-wide portfolio of 2011-2016 |$34 millionDSM/EE programs within first six years e Begin detailed engineering and permitting activities 2011-2016 Varies by associated with the generation projects identified in the project initial years of the preferred resource plan,including: o Projects under development (HCCP,Southcentral Power Project,Fire Island Wind Project,and Nikiski Wind Project) o Glacier Fork Hydroelectric Project o Generic Anchorage MSW Project o Generic GVEA MSW Project o GVEA North Pole Retrofit Project o Mt.Spurr Geothermal Project o Chakachamna Hydroelectric Project o Susitna Hydroelectric Project e Begin detailed engineering and permitting activities 2011-2016 Varies by associated with the transmission projects identified in the project initial years of the preferred resource plan,including: o Soldotna to Quartz Creek Transmission Line o Quartz Creek to University Transmission Line o Douglas to Teeland Transmission Line o Lake Lorraine to Douglas Transmission Line o SVCs ©Funds to undertake the study of the Southern Intertie o Funds to investigate the provision of regulation that will facilitate the integration of renewable energy projects into the Railbelt system Black &Veatch 1-43 February 2010 SECTION 1 EXECUTIVE SUMMARY 1.10.3 Supporting Studies and Activities Table 1-13 ALASKA RIRP STUDY Near-Term Implementation Action Plan -Supporting Studies and Activities Actions Category Description Timeline Est.Cost Supporting Studies and Activities The State Legislature should appropriate funds for the initial stages of the development of a regional DSM/EE program,including 1)region-wide residential and commercial end-use saturation surveys,2)residential and commercial customer attitudinal surveys,3)vendor surveys,4)comprehensive evaluation of economically achievable potential,and 5)detailed DSM/EE program design efforts Develop a regional DSM/EE program measurement and evaluation protocol The State and Railbelt utilities should work closely with resource agencies to identify environmental issues and permitting requirements related to large hydroelectric and tidal projects Conduct necessary studies to address resource agencies' issues and data requirements related to large hydroelectric and tidal projects Complete a regional economic potential assessment, including the identification of the most attractive sites,for all renewable projects included in the preferred resource plan Develop a regional frequency regulation strategy for non- dispatchable resources Develop a regional standard power purchase agreement for IPP-developed projects Develop a regional competitive power procurement process to encourage IPP development of projects included in the preferred resource plan 2010-2011 2012 2010-2011 2011-2012 2010-2012 2011 2011-2012 2011-2012 $1.0 million $0.1 million $0.2 million To be determined $1.5 million $0.5 million $0.2 million $0.2 million Black &Veatch 1-44 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.10.4 Other Actions Table 1-14 Near-Term Implementation Action Plan -Other Actions Actions Category Description Timeline Est.Cost Other Actions Forma regional entity (if GRETC is not formed)to 2010-2011 Subject to develop and deliver DSM/EE programs to residential and decision commercial customers throughout the Railbelt region,in regarding close coordination with the Railbelt utilities formation of GRETC Establish close coordination between the Railbelt electric 2010-2011 4 $0.2 million utilities,Enstar and AHFC regarding the development and delivery of DSM/EE programs Aggressively pursue available Federal funding for 2010-2011 |$0.2 million DSM/EE programs Form a regional entity (if GRETC is not formed)and 2011-2012 Subject to encourage IPPs to identify and develop renewable projects decision that are included in the preferred resource plan regarding formation of GRETC Further encourage the development of tidal power Ongoing To be determined Monitor,and influence to the degree possible,Federal Ongoing Not legislative and regulatory activities,including those related applicable to emissions regulations Aggressively pursue available Federal funding for 2010-2012 |$0.2 million renewable projects Develop streamlined siting and permitting processes for 2010-2011 |$0.5 million transmission projects Monitor the licensing progress of small modular nuclear Ongoing Not units applicable Black &Veatch 1-45 February 2010