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BURRO CREEK
HYDROELECTRIC FEASIBILITY STUDY
FINAL REPORT
N OVEMBER 2011
Prepared For
BURRO CREEK HOLDINGS, LLC
P.O. BOX 271
SKAGWAY, ALASKA 99840
Prepared By
polarconsult alaska, inc.
and
Southeast Strategies
BURRO CREEK HYDROELECTRIC FEASIBILITY STUDY
FINAL REPORT
NOVEMBER 2011
PREPARED FOR:
BURRO CREEK HOLDINGS, LLC
PO BOX 271
SKAGWAY, AK 99840
PREPARED BY:
polarconsult alaska, inc.
1503 West 33rd Avenue, Suite 310
Anchorage, AK 99503
AND:
Southeast Strategies
900 1st Street, Suite 12
Douglas, AK 99824
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report i
EXECUTIVE SUMMARY
Burro Creek Holdings, LLC (BCH) received a grant from the Alaska Energy Authority in 2009
to perform a feasibility study of upgrading the existing 15‐kilowatt (kW) run‐of‐river
hydroelectric system on Burro Creek. In 2010, BCH contracted Southeast Strategies and
Polarconsult Alaska, Inc. to prepare a feasibility study to evaluate hydroelectric upgrade
options, develop estimated upgrade costs, and evaluate the market for the project’s energy in
the Upper Lynn Canal region. This report presents the findings of the feasibility study.
Hydropower Resource
Because Burro Creek is across Lynn Canal from Skagway, the existing project produces
insufficient energy to justify an interconnection with Skagway. Instead, a range of new larger
run‐of‐river projects at Burro Creek were investigated in this study. Storage projects were also
considered, but the topography of the Burro Creek valley is not suitable for cost‐effective
construction of reservoirs of significant capacity for the projects considered. The run‐of‐river
configurations considered in this study range in installed capacity from 430 kilowatts up to 7.3
megawatts (MW). This range is developed by considering different design flows and different
elevations for diversion sites on Burro Creek. The figure below shows the location of BCH
property relative to Skagway and the diversion sites considered in this study.
Project configurations with a capacity of up to 2.2 MW are located wholly on the BCH property.
Projects with larger capacities are partially located on Federal land upstream of BCH property.
All project configurations require a submarine cable from Burro Creek to Skagway to deliver
power to potential
markets. The mostly
fixed cost of this
submarine cable
makes the smaller
project configurations
less competitive than
larger configurations
since the larger
projects can spread
this fixed cable cost
over increased energy
sales. This enables
the larger project
configurations to be
profitable at a lower
$/kWh sales price.
Market For Energy
The market for energy from a Burro Creek project is not well defined at this time. The amount
and seasonal availability of energy from Burro Creek does not mesh well with the needs of
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report ii
existing markets in the Upper Lynn Canal region. Existing markets include Haines and
Skagway, served by Alaska Power Company (APC) (a subsidiary of Alaska Power and
Telephone, Inc. (AP&T)), and the Chilkat Valley communities served by Inside Passage Electric
Cooperative, Inc. (IPEC). These are summarized below.
Possible sales of up to 240,000 kWh annually to IPEC for resale to customers in Klukwan
and the Chilkat Valley near Haines.
Possible sales up to 500,000 kWh annually to APC to displace energy APC currently
generates with diesel fuel. Most of these sales would occur in late winter, when APC’s
hydroelectric facilities are not operating, or are operating at reduced capacity.
The Regulatory Commission of Alaska allows independent power producers such as BCH
to sell power to businesses held in common without the power producer having to become a
certified utility. Businesses held in common currently use about 110,000 kWh of power
annually.
By themselves, these existing markets are too small to justify a new project at Burro Creek.
Projected growth trends in these markets are slightly negative, and thus not favorable for
development of Burro Creek. However, these markets may prove viable in combination with
the potential market opportunities discussed below, and warrant future consideration.
Three potential future market opportunities were identified that could be viable market(s) for
Burro Creek energy. These markets will depend on future developments and warrant
continued attention:
Sales to Yukon Territory. The Yukon Territory is experiencing a boom in mining activity,
and the crown utility (Yukon Energy) is actively seeking additional capacity to meet mining
demand. Yukon Energy would consider extending its transmission line to the U.S. border to
connect with the Upper Lynn Canal grid if Burro Creek or other hydroelectric projects offer
sufficient energy at a suitable price. APC’s existing lines end approximately 7 miles from
the border. It appears Burro Creek can meet Yukon Energy’s criteria for a line extension.
Sales to APC during the summer season if APC develops infrastructure to provide shore
power to cruise ships docked in Skagway. This opportunity may be dependant on the
development of additional hydroelectric power in the region, as the combined output of
Burro Creek and the excess power currently available from APC would not be enough to
meet demand from the cruise ships.
Sales to APC if the Palmer mining prospect north of Haines is developed.
Serving one of these three future markets is considered the best opportunity for a new project at
Burro Creek. Development of additional hydropower resources in the region will strongly
influence whether demand for the full‐year output of Burro Creek power will materialize.
Project Feasibility
This study identified several project configurations that appear to be compatible with potential
future markets in the Upper Lynn Canal region with regard to estimated energy price and
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report iii
energy output. At this time, the preferred project configuration is not known, because it will
depend on the need for power from the market and further study to better refine development
costs. Table ES‐1 summarizes the project configurations that have promising estimated energy
prices and may reasonably match future market demand. Details for all project configurations,
funding, and market scenarios are presented in Appendix H of this report.
Two other major variables will influence the energy sales price from a project at Burro Creek.
These variables are (1) the potential use of grant funds and (2) how much of the project’s output
will be sold. This study considered two grant funding scenarios for all project configurations:
no grant funding, and 50% grant funding up to a cap of $8.5 million in grants. This study
considered two energy sales scenarios: sale of a project’s full output, and sale of only 80% of a
project’s potential output. These scenarios are presented in Table ES‐1.
Based on currently available information, a connection to the Canadian power grid, and/or
development of the mine north of Haines could provide a year‐round market for Burro Creek
energy. A combination of existing market opportunities and providing shore power to cruise
ships in Skagway could result in only partial‐year demand for Burro Creek energy.
In market situations where power is not sold directly to APC, Burro Creek would likely have to
pay a charge to APC (called a “wheeling” charge) of about $0.02 per kWh for use of APC’s
electric lines. That wheeling charge is figured into the power sales rates in Table ES‐1.
Other Proposed Project in the Region
Several future hydroelectric projects are under consideration in the Haines/Skagway area.
Connelly Lake is a storage facility near Haines with a 10 to 15 MW capacity potential. That
project could be completed by 2016. Schubee Lake is a storage facility across Lynn Canal from
Haines with a 3 to 5 MW potential capacity, which could be completed by 2019. It is likely that
only one of those two facilities will be built. A smaller run‐of‐river system at Walker Lake near
Haines has been considered, but its 1 MW capacity potential may not warrant development.
Any of these facilities will help create the additional system capacity needed for APC to develop
shoreside electrical connections for cruise ships in Skagway, thus creating a market for Burro
Creek power in the summer season.
Near Skagway, a 25 to 50 MW potential capacity storage facility at West Creek is being
considered, and could be completed by 2018. Plans for this facility include an intertie across the
Canadian border to connect to the Canadian power grid. Once an intertie is developed,
virtually all the power produced in the Haines/Skagway area could be sold to the Canadian
grid.
Burro Creek Holdings, LLC Burro Creek Hydroelectric Study Polarconsult Alaska, Inc. November 2011 – Final Report iv Table ES‐1: Project Configurations, Funding Scenarios, and Sales Scenarios with Lowest Estimated Power Sales Rates Source: Polarconsult Alaska, Inc., October 2011. * The estimated sales price for full sales scenarios includes a $0.02/kWh wheeling charge for use of APC transmission and distribution system to deliver Burro Creek energy to market. 1: The configuration codes such as ‘3D‐70’ are defined as: the number (1 – 5) is the diversion location, the letter (A – D) is the powerhouse site, and the number after the hyphen is the design flow in cubic feet per second. 2: Full sales assumes that all of the net output of the project is sold. Partial sales assumes that all of the net output of the project from April 1st through September 30th (or an equivalent amount of energy distributed throughout the year) is sold. 3: Up to a maximum of $8,500,000 in grant funding. Project Configuration 1 1D‐70 1D‐70 2D‐70 2D‐70 3D‐70 3D‐70 1D‐110 1D‐110 2D‐110 2D‐110 3D‐110 3D‐110 Amount of Project Output Sold 2 Full Sales Partial Sales Full Sales Partial Sales Full Sales Partial Sales Full Sales Partial Sales Full Sales Partial Sales Full Sales Partial Sales Project Design Flow (cubic feet per second) 70 110 Project Head (feet) 1,130 gross 1,030 net 970 gross 880 net 770 gross 710 net 1,130 gross 1,030 net 970 gross 880 net 770 gross 710 net Penstock Length and Diameter 12,600 feet 36‐inch 10,300 feet 36‐inch 7,600 feet 36‐inch 12,600 feet 42‐inch 10,300 feet 42‐inch 7,600 feet 42‐inch Installed Hydroelectric Capacity (kilowatts, kW) 4,400 3,800 3,400 7,300 6,500 5,250 Estimated Total Capital Cost (2011$, millions) $17.2 M $13.9 M $11.1 M $21.1 M $16.8 M $13.8 M Expected Annual Energy Sales (megawatt‐hours, MWh) 17,943 13,981 15,935 12,340 13,127 10,074 20,581 16,672 18,798 15,172 15,915 12,747 Estimated Energy Sales Price, No Grants ($ per kWh) $0.151* $0.165 $0.140* $0.152 $0.138* $0.150 $0.159* $0.169 $0.143* $0.149 $0.140* $0.146 Estimated Energy Sales Price, with Grants for 50% of Development Cost 3 ($ per kWh) $0.102* $0.102 $0.095* $0.094 $0.0938 $0.093 $0.113* $0.111 $0.097* $0.092 $0.095* $0.090
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report v
Recommendations
A project at Burro Creek is estimated to take five years to complete once a viable market for the
project is secured. The following actions are recommended to continue advancing a hydro
project at Burro Creek:
Contact the Regulatory Commission of Alaska (RCA) to determine how best to move
forward. The RCA governs sales of power in Alaska, and it is important to understand
the conditions under which a company can sell power to various customers. In general,
an independent power producer such as Burro Creek cannot sell to more than 10
customers or over $50,000 worth of power per year without becoming a certified utility.
In addition, RCA generally will not allow two certified utilities within one service area
However, the RCA Commissioners have the final say on such projects, and can make
exceptions to their regulations as they determine is in the public interest. Appendix F
contains the Alaska Statute language that may be pertinent to this project.
Continue stream gauging at Burro Creek to characterize the resource potential.
Monitor future land management decisions for the BLM land west of Burro Creek to
insure the land remains open to hydropower development.
Maintain Burro Creek as a generation resource in regional energy planning documents,
such as the Southeast Alaska Integrated Resource Plan, currently under development by
the Alaska Energy Authority (AEA).
Contact Yukon Energy to discuss the possible extension of its power transmission line
south to the Upper Lynn Canal system, and a possible power purchase agreement.
Contact the developers of the Palmer Mine to monitor the progress of that project, and if
and when development is assured, to discuss possible power purchase agreements.
Contact APC to discuss the conditions under which they may be willing to purchase
wholesale power from BCH.
Contact IPEC to discuss a possible power purchase agreement, keeping in mind that
other market opportunities may need to exist in order to make this market viable.
Contact possible funding sources to identify grants and loan programs that may reduce
the cost of energy from the Burro Creek project.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report vi
TABLE OF CONTENTS
1.0 INTRODUCTION ................................................................................................................................1
1.1 PROJECT AUTHORIZATION AND PURPOSE ...........................................................................................1
1.2 PROJECT EVALUATION PROCESS ..........................................................................................................1
1.3 EXISTING HYDROELECTRIC PROJECT AND CURRENT STUDY ................................................................1
2.0 COMMUNITY PROFILE.....................................................................................................................4
2.1 COMMUNITY OVERVIEW......................................................................................................................4
2.2 EXISTING ENERGY SYSTEM ...................................................................................................................8
3.0 HYDROELECTRIC DEVELOPMENT OPTIONS...........................................................................15
3.1 RESOURCE DESCRIPTION ...................................................................................................................15
3.2 OVERVIEW OF PROJECT CONFIGURATIONS CONSIDERED ...................................................................16
3.3 RECOMMENDED PROJECT CONFIGURATIONS .....................................................................................16
3.4 ESTIMATED ENERGY GENERATION ....................................................................................................17
3.5 DESCRIPTION OF PROJECT FEATURES .................................................................................................18
4.0 MARKET ANALYSIS AND OPPORTUNITIES.............................................................................21
4.1 MARKET FOR POWER.........................................................................................................................21
4.2 PROJECT COST ESTIMATES .................................................................................................................23
4.3 POTENTIAL BURRO CREEK BUSINESS OPPORTUNITIES .......................................................................23
4.4 OTHER INTANGIBLE PROJECT BENEFITS .............................................................................................24
5.0 CONCLUSIONS AND RECOMMENDATIONS ...........................................................................25
5.1 DEVELOPMENT PLAN & SCHEDULE ...................................................................................................25
5.2 RECOMMENDATIONS FOR IMPLEMENTATION.....................................................................................26
APPENDICES
APPENDIX A – MAPS AND FIGURES
APPENDIX B – PHOTOGRAPHS
APPENDIX C – HYDROLOGY DATA
APPENDIX D – RESOURCE DATA AND ANALYSIS
APPENDIX E – ENVIRONMENTAL CONSIDERATIONS
APPENDIX F – PERMITTING INFORMATION
APPENDIX G – TECHNICAL ANALYSIS
APPENDIX H – CAPITAL COST ESTIMATES AND FINANCIAL SCENARIOS
APPENDIX I – ACRONYMS AND TERMINOLOGY
APPENDIX J – 1982 REPORT ON ORIGINAL BURRO CREEK HYDROELECTRIC PROJECT
“APPROPRIATE TECHNOLOGY REPORT: HYDROELECTRIC SYSTEM AT BURRO CREEK”
APPENDIX K – AEA REVIEW COMMENTS, AUTHOR RESPONSES, AND CORRESPONDENCE
WITH YUKON ENERGY
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report vii
LIST OF FIGURES
Figure 2‐1: Haines/Skagway Moderate Electrical Demand Forecast, 2012 to 2062 ....................... 14
Figure 3‐1: Estimated Average Annual Net Output of Project 3D‐70 ............................................. 17
Figure 5‐1: Project Development Schedule .......................................................................................... 26
Figure A‐1: Project Overview and Location Map ............................................................................. A‐1
Figure A‐2: Potential Diversion Sites and Drainage Basins ............................................................ A‐2
Figure A‐3: Map of Project Configurations on USS 1560 ................................................................ A‐3
Figure A‐4: Map of Project Configurations Using Federal Lands ................................................... A‐4
Figure A‐5: Map of Transmission Routes ........................................................................................... A‐5
Photograph B‐1: Burro Creek Site from Lynn Canal ........................................................................ B‐1
Photograph B‐2: Burro Creek Waterfall, Looking Upstream .......................................................... B‐1
Photograph B‐3: Burro Creek Gauging Station, Looking Downstream ........................................ B‐1
Photograph B‐4: Existing Burro Creek Intake, Looking Upstream ................................................ B‐2
Photograph B‐5: Existing Burro Creek Intake Screening Box ......................................................... B‐2
Photograph B‐6: Existing Burro Creek Intake ................................................................................... B‐2
Photograph B‐7: Burro Creek from Skagway .................................................................................... B‐3
Photograph B‐8: Burro Creek Gauging Station ................................................................................. B‐4
Photograph B‐9: Typical Terrain and Vegetation in Project Area .................................................. B‐5
Photograph B‐10: Existing Penstock ................................................................................................... B‐5
Photograph B‐11: Existing Penstock ................................................................................................... B‐6
Photograph B‐12: Existing Penstock ................................................................................................... B‐6
Photograph B‐13: Existing Powerhouse ............................................................................................. B‐6
Photograph B‐14: Existing Turbine and Generator .......................................................................... B‐7
Photograph B‐15: Burro Creek at USS 1560 Property Line ............................................................. B‐7
Figure C‐1: Burro Creek Stage Data ................................................................................................... C‐2
Figure C‐2: Model Used for Creek Section at Burro Creek ............................................................ C‐4
Figure C‐3: Burro Creek Stream Gauge Rating Curve ..................................................................... C‐4
Figure C‐4: Burro Creek Hydrograph ................................................................................................ C‐5
Figure C‐5: Burro Creek and Taiya River Flow Data and Models ................................................. C‐8
Figure C‐6: Extended Burro Creek Record Using Taiya River Flow Model ................................. C‐9
Figure C‐7: Daily Flow Statistics for Extended Burro Creek Flow Record ................................. C‐10
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report viii
LIST OF TABLES
Table ES‐1: Project Configurations, Funding Scenarios, and Sales Scenarios with Lowest
Estimated Power Sales Rates .............................................................................................. iv
Table 2‐1: Population of Haines and Skagway, 2000 to 2010 .............................................................. 4
Table 2‐2: Employment in Haines and Skagway, 2000 to 2010 ........................................................... 5
Table 2‐3: Summer Visitors at Haines and Skagway, 2000 to 2010 .................................................... 6
Table 2‐4: Recent Electric System Statistics ......................................................................................... 10
Table 2‐5: Changes in Population and Energy Consumption in Haines and Skagway,
2004 to 2010 .......................................................................................................................... 11
Table 2‐6: Haines/Skagway Electrical Demand Forecast, 2012 to 2062 ........................................... 13
Table 3‐1: Project Configurations Considered .................................................................................... 16
Table 4‐1: Comparison of Potential Project Costs and Required Power Prices Projects
Over 4 MW in Capacity ...................................................................................................... 24
Table C‐1: Burro Creek Flow Measurements .................................................................................... C‐2
Table C‐2: Manning Equation Parameters for Gauging Station ..................................................... C‐3
Table C‐3: Creek Sections used to Calculate A and P at Gauging Stations .................................. C‐4
Table C‐4: Summary of Hydrology Data for Burro Creek and Nearby Resources...................... C‐6
Table C‐5: Burro Creek Flow Model Parameters .............................................................................. C‐7
Table D‐1: Maximum Probable Floods at Burro Creek .................................................................... D‐1
Table G‐1: Range of Project Options Considered ............................................................................. G‐1
Table G‐2: Diversion Site Considerations .......................................................................................... G‐2
Table G‐3: Powerhouse Site Considerations ..................................................................................... G‐6
Table G‐4: Expected Plant Capacity Factor for Different Project Configurations ........................ G‐7
Table G‐5: Average Monthly and Annual Energy Generation of Project Configurations .......... G‐9
Table G‐6: Estimated Costs for Power Line – Burro Creek to Skagway ...................................... G‐10
Table H‐1: Cost Estimates and Financial Analysis for Select Project Configurations ................ H‐3
Table H‐2: Economic Cases for Select Project Configurations ....................................................... H‐4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report ix
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report 1
1.0 INTRODUCTION
1.1 PROJECT AUTHORIZATION AND PURPOSE
Burro Creek Holdings, LLC (BCH) received a grant from the Alaska Energy Authority in 2009
to perform a feasibility study for an upgrade of the existing run‐of‐river hydroelectric system.
In 2010, BCH contracted Southeast Strategies (SES) and Polarconsult Alaska, Inc. (Polarconsult)
to prepare a feasibility study to determine costs of the development and increased operations
costs, and whether there was a market for this power in the Skagway area.
This feasibility study:
Quantifies the hydropower resource at Burro Creek,
Identifies the most economical hydropower development at Burro Creek,
Provides feasibility‐level cost estimates for several hydro project configurations,
Evaluates possible markets for power from Burro Creek, and
Makes recommendations for future development of Burro Creek’s hydropower
potential.
This report presents the findings of the feasibility study.
1.2 PROJECT EVALUATION PROCESS
Resource data for Burro Creek was collected and analyzed to identify several project
configurations for further evaluation. The resource data included stream hydrology, site
topography, land ownership and related information. Environmental and regulatory factors
were also considered in developing these project configurations. Cost estimates were
developed for these project configurations, and hypothetical financing and business models
were applied in order to estimate energy sales rates for each configuration.
Future markets for power were evaluated to determine if there is an opportunity for Burro
Creek to supply future demand in the region. The three developing markets described in
Section 4.2 were identified. These market scenarios were then further analyzed to identify the
amount of project output that could be sold, and the seasonal timing and sales price that would
be necessary. These potential developing markets warrant continued attention, as close
coordination will be necessary in order to dovetail the development schedules of these potential
buyers with the development schedule of Burro Creek.
1.3 EXISTING HYDROELECTRIC PROJECT AND CURRENT STUDY
1.3.1 Existing Hydroelectric Project
There is an existing small run‐of‐river hydroelectric project on Burro Creek which was built in
1982 by Captain Gene Richards, a retired NOAA captain. The project was constructed in part
with funds from an Alaska Energy Authority Grant, and was used to support the Richardsʹ
homestead and fish hatchery for nearly 20 years. Gene Richardsʹ report entitled ʺAppropriate
Technology Report: Hydroelectric System at Burro Creekʺ is attached as Appendix J.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report 2
This existing hydro project is suitable for meeting on‐site demand at Burro Creek. The existing
project includes the following:
A diversion structure at 235’ elevation consisting of a natural rock sill in Burro Creek, a
blasted notch in this sill fitted with a 10‐inch diameter PVC intake pipe, and a milled log
pinned into the apex of the rock sill with 1‐inch iron bars to create a deeper
impoundment.
An approximately 3‐foot by 4‐foot by 8‐foot timber filter box located approximately 30
feet downstream from the diversion. Raw water from the diversion discharges into the
box, passes through a coarse fiberglass screen, and enters the penstock. This box
prevents excessive rocks, sticks, or gravel from entering the penstock, and stabilizes
water flow into the project.
A 1,400‐foot long 10‐inch diameter PVC penstock that conveys water from the intake
down to the powerhouse.
An approximately 12‐foot by 12‐foot milled‐log powerhouse with a finished floor
elevation of 32.5 feet that contains the turbine and generation equipment.
The original turbine equipment, which includes two 2‐jet Pelton wheels on a common
shaft that drive a 25 kilowatt (kW) alternator via pulleys and belt drive. The second jet
on each wheel was blanked off inside the turbine housing during original manufacture
of the turbine equipment. This turbine set has the potential to generate 50 kW, although
the second jets would need to be installed and the belt drive and alternator would need
to be upgraded. This equipment is not currently functional. It is not known when this
equipment was last operational, or what measures are needed to place it back into
service.
Newer turbine‐generator equipment, consisting of one single‐jet home‐made Pelton‐type
wheel driving a 15 kW alternator via a belt drive. The turbine is governed by a
Woodard UG‐8 mechanical governor, which actuates the jet deflector to regulate
frequency and voltage. This turbine‐generator installation currently provides Burro
Creek with electricity.
A shallow‐burial tailrace pipe that discharges water into Burro Creek just above
tidewater.
The existing 15‐kW hydro project is functional, but has significant deferred maintenance. The
diversion pipe and head box is past its useful life and in need of replacement; thrust restraints
along the entire penstock are in need of re‐tensioning, adjustment, or replacement; and some of
the thrust restraints in the powerhouse are in marginal condition. The electrical panel in the
powerhouse also appears to be substandard and may warrant upgrade.
The existing hydro project is an good example of a small (15 to 50 kW) rural Alaskan
hydroelectric project. The siting and construction methods used for this project are excellent
example of simple, economical, and appropriate micro hydro development at a remote site.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report 3
However, the existing project is too small to justify export of power from Burro Creek, and is
not considered further in this study.
1.3.2 Current Study
This feasibility study included the following activities:
R&M Engineers, Inc. performed an as‐built survey of the existing micro hydro project at
Burro Creek in the fall of 2009 to identify the head and location of the project on USS
1560.
Polarconsult visited Burro Creek on December 17 to 18, 2009 to install a stream gauge
and measure flow in Burro Creek to collect site‐specific hydrology data for this study.
Polarconsult also conducted an initial reconnaissance of the lower reaches of Burro
Creek on USS 1560.
Polarconsult conducted additional site investigations at Burro Creek in May 2010 and
September 2011. Activities during these visits included limited topographic surveys to
determine the available head and location of various intake sites, assessment of terrain
and identification of penstock routes and construction requirements, initial assessment
of basic environmental conditions in the project area (e.g., presence or absence of
wetlands), and additional flow measurements.
Southeast Strategies visited Burro Creek in August 2011 to review the project site and be
familiarized with the project setting and terrain.
BCH personnel have periodically downloaded and maintained the stream gauge
throughout the feasibility study.
Several potential hydro project configurations on Burro Creek were developed,
including cost estimates and financial analysis of each configuration.
Existing and future potential markets for the energy from Burro Creek were analyzed.
Recommendations for future efforts at Burro Creek were developed.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report 4
2.0 COMMUNITY PROFILE
2.1 COMMUNITY OVERVIEW
Burro Creek is located along the shores of Taiya Inlet in Lynn Canal, about two miles southwest
of Skagway, in Southeast Alaska. Skagway is located about 90 miles northeast of Juneau in
Upper Lynn Canal, and Burro Creek is accessed by boat or helicopter from Skagway. The
Upper Lynn Canal communities on the electric grid that will be served by the Burro Creek
hydroelectric project include Haines, Klukwan, and Skagway, as well as some outlying areas.
The Upper Lynn Canal area has a maritime climate with cool summers and mild winters.
Because it is in the rain shadow of nearby mountains, Skagway receives less precipitation than
Haines and many communities in the Southeast Alaska region, averaging 26 inches of
precipitation per year, which includes 39 inches of snow. Both Haines and Skagway have
commercial airports, and are ports of call for the State ferry system. In addition, Skagway is
connected by the Klondike Highway to the Alaska Highway, and the North American road
system. Haines is also connected to the Alaska Highway via the Haines Highway.
Skagway is one of the oldest communities in Alaska, beginning as an access to the Klondike
gold region in the late 1880s. It was incorporated as Alaska’s first city in 1900, and became a
fully consolidated borough in 2004. Haines housed the first permanent military post in Alaska,
Fort William H. Seward, built in 1904. It was incorporated as a city in 1910, and formed a
borough in 2007.
Table 2‐1 presents population in both Haines and Skagway between 2000 and 2010. The
estimated summer population reflects the influx of summer workers for the tourism season.
Table 2‐1: Population of Haines and Skagway, 2000 to 2010
Year Skagway Haines Both Summer
Estimate*
Annual
Average Percent Change
2000 862 2,392 3,254 4,978 3,829
2001 838 2,383 3,221 4,897 3,780 ‐1.3%
2002 844 2,373 3,217 4,905 3,780 0.0%
2003 843 2,335 3,178 4,864 3,740 ‐1.0%
2004 873 2,271 3,144 4,890 3,726 ‐0.4%
2005 834 2,225 3,059 4,727 3,615 ‐3.0%
2006 855 2,252 3,107 4,817 3,677 1.7%
2007 843 2,264 3,107 4,793 3,669 ‐0.2%
2008 846 2,322 3,168 4,860 3,732 1.7%
2009 865 2,286 3,151 4,881 3,728 ‐0.1%
2010 968 2,508 3,476 5,412 4,121 10.6%
Average Annual Change +0.8%
Sources: Alaska Department of Labor and Workforce Development and Southeast Strategies, 2011.
*Summer population estimates by Southeast Strategies assume that the population in Skagway about triples in the
summer season.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report 5
Both communities have strong tourism sectors. In addition, Haines hosts a commercial fishing
fleet of around 100 residents. Many of the jobs in these communities are seasonal. The
following table shows employment in Haines and Skagway. Skagway appears to have a more
stable employment base than Haines. Both communities have lost employment between 2009
and 2010.
Table 2‐2: Employment in Haines and Skagway, 2000 to 2010
Year Haines Percent
Change Skagway Percent
Change
Both
Communities
Percent
Change
2000 805 656 1,461
2001 683 ‐15.2% 684 4.3% 1,367 ‐6.4%
2002 893 30.7% 745 8.9% 1,638 19.8%
2003 947 6.0% 749 0.5% 1,696 3.5%
2004 1,002 5.8% 780 4.1% 1,782 5.1%
2005 1,050 4.8% 836 7.2% 1,886 5.8%
2006 730 ‐30.5% 848 1.4% 1,578 ‐16.3%
2007 763 4.5% 877 3.4% 1,640 3.9%
2008 981 28.6% 886 1.0% 1,867 13.8%
2009 1,017 3.7% 826 ‐6.8% 1,843 ‐1.3%
2010 995 ‐2.2% 812 ‐1.7% 1,807 ‐2.0%
Average
Annual Change 3.6% 2.2% 2.6%
Source: Alaska Department of Labor and Workforce Development.
Both Haines and Skagway are connected to the continental road system, and they receive many
visitors in the summer season (see Table 2‐3). In addition, they both receive scheduled and
chartered air traffic, which increases greatly in summer. State ferry service is also available
daily in the summer and several times weekly during the rest of the year. Both communities
receive visits by cruise ships in summer. Haines gets about one large cruise ship per week, and
Skagway can receive as many as 20 per week. The following table presents visitation by mode
at Haines and Skagway.
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Table 2‐3: Summer Visitors at Haines and Skagway, 2000 to 2010
Year Cruise Ship Highway State Ferry Train Total Percent
Change
2000 ‐ Total 753,036 139,305 56,892 19,231 968,464
Haines 187,397 44,380 27,494 259,271
Skagway 565,639 94,925 29,398 19,231 709,193
2001 ‐ Total 639,670 128,923 46,287 20,674 835,554 ‐13.7%
Haines 40,150 46,294 22,575 109,019 ‐58.0%
Skagway 599,520 82,629 23,712 20,674 726,535 2.4%
2002 ‐ Total 698,112 128,538 52,122 14,361 893,133 6.9%
Haines 86,474 48,117 25,309 159,900 46.7%
Skagway 611,638 80,421 26,813 14,361 733,233 0.9%
2003 ‐ Total 654,483 118,756 49,413 13,065 835,717 ‐6.4%
Haines 14,741 44,006 24,383 83,130 ‐48.0%
Skagway 639,742 74,750 25,030 13,065 752,587 2.6%
2004 ‐ Total 744,560 121,393 46,901 13,187 926,041 10.8%
Haines 22,465 43,556 23,227 89,248 7.4%
Skagway 722,095 77,837 23,674 13,187 836,793 11.2%
2005 ‐ Total 804,300 112,280 43,464 17,071 977,115 5.5%
Haines 31,968 40,893 22,200 95,061 6.5%
Skagway 772,332 71,387 21,264 17,071 882,054 5.4%
2006 ‐ Total 786,592 101,010 44,060 17,826 949,488 ‐2.8%
Haines 31,278 39,140 23,899 94,317 ‐0.8%
Skagway 755,314 61,870 20,161 17,826 855,171 ‐3.0%
2007 ‐ Total 843,922 108,193 38,780 16,514 1,007,409 6.1%
Haines 23,178 39,338 20,531 83,047 ‐11.9%
Skagway 820,744 68,855 18,249 16,514 924,362 8.1%
2008 ‐ Total 807,262 100,260 40,399 18,326 966,247 ‐4.1%
Haines 41,770 34,434 22,404 98,608 18.7%
Skagway 765,492 65,826 17,995 18,326 867,639 ‐6.1%
2009 ‐ Total 798,644 173,781 79,666 16,159 1,068,250 10.6%
Haines 41,304 33,931 19,812 95,047 ‐3.6%
Skagway 757,340 139,850 59,854 16,159 973,203 12.2%
2010 ‐ Total 726,490 103,044 38,524 16,822 884,880 ‐17.2%
Haines 30,850 36,806 21,330 88,986 ‐6.4%
Skagway 695,640 66,238 17,194 16,822 795,894 ‐18.2%
Sources: Haines and Skagway Visitors Bureaus, Alaska Marine Highways Traffic Volume Reports.
Note: Some visitors arriving by State ferry and highway may be local residents. In addition, some visitors arrive by
air, passenger‐only ferries, and private boat.
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November 2011 – Final Report 7
Visits to Haines and Skagway have generally grown between 2000 and 2010. However, cruise
passenger visits dropped slightly between 2007 and 2010, and appear to have dropped slightly
again in 2011. According to the Cruise Line Agencies of Alaska, in 2012, cruise ship stops at
Haines will remain the same at 23. Cruise ship ports of call at Skagway in 2012 will increase by
8, to 352 stops. Assuming a similar load factor of passengers per ship as recent years, this
increase should bring more passengers to Skagway in summer of 2012.
Many of the cruise ships visiting these communities house 2,000 or more passengers, and 1,000
or more crew. As a result of these visitations, it is not unusual for Skagway to have an
additional 10,000 people in the town on any given summer day. Skagway’s status as the
gateway to the Klondike, and its Yukon Gold Rush historical flavor is a strong tourism draw,
and virtually every cruise ship transiting Alaska’s Inside Passage visits the community. Cruise
ship calls in Haines are far fewer, averaging one large cruise ship visit per week. Haines also
lacks the train traffic that Skagway has.
Potential future industrial development in the Upper Lynn Canal includes the Palmer mining
project near Haines. This is a mid‐stage prospect containing high grade copper, zinc, gold, and
silver. The project is still in the exploration phase to better define the existing inferred resource.
The Palmer project could potentially require large amounts of electric power to develop and
operate.
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2.2 EXISTING ENERGY SYSTEM
Alaska Power Company (APC) is the certificated electric utility in the Skagway area. The utility
is also connected to the Haines area by undersea cable. Inside Passage Electric Cooperative
(IPEC) provides retail electric power to Klukwan and the Chilkat Valley near Haines, some of
which is purchased wholesale from APC. In this report, the Municipality of Skagway and the
Haines Borough (the area is also referred to as Upper Lynn Canal) are taken together as the
project area into which the Burro Creek upgrade integrates.
2.2.1 Electric Utility Organization
Electrical service in Upper Lynn Canal is provided by APC, a subsidiary of Alaska Power and
Telephone (AP&T). The utility holds Certificate of Public Need and Necessity No. 2. It is a for‐
profit utility, and operates under statutory authority AS 42.05.990(5)(A). The APC is the entity
that operates the power distribution system serving Upper Lynn Canal. The generation plants
are owned by either AP&T or APC. The APC participates in the State of Alaska’s Power Cost
Equalization (PCE) program, which subsidizes electricity rates for residences and community
facilities served by eligible Alaska utilities.
2.2.2 Electrical Generation System
The AP&T currently operates four hydroelectric generation facilities and two diesel plants in
Upper Lynn Canal. Historically, one diesel generation plant operated in Skagway and one in
Haines. A four‐generator diesel plant at Haines has the capacity to generate about 6.4
megawatts (MW) of power, and a four‐generator diesel plant at Dewey Lakes near Skagway has
a generating capacity of about 3.4 MW. Diesel generation is used mainly for backup power
when the hydroelectric systems are not operating.
The 900 kW Dewey Lakes hydroelectric run‐of‐river project has operated near Skagway since
1909. In 1997, the Goat Lake hydroelectric project began operations. This 4.0 MW facility is
located seven miles north of Skagway, and consists of a 204‐acre glacier fed lake that has winter
storage enough to provide hydroelectric power nearly year around. The facility was connected
to the Haines power grid by a 15‐mile undersea cable in 1998. In 2009, the Kasidaya Creek run‐
of‐river hydroelectric project near Skagway began operating. That facility has a generation
capacity of 3.0 MW, and is not operational during some winter months. The Lutak Hydro run‐
of‐river system near Haines has an installed capacity of 250 kW.
In addition to these AP&T facilities, the privately owned 10‐Mile Creek run‐of‐river
hydroelectric facility north of Haines has a capacity to generate 600 kW. Currently that facility
sells its power to IPEC for use in Klukwan and the Chilkat Valley. IPEC is in the process of
acquiring the 10‐Mile Creek facility.
The installed capacity of these power plants totals over 8.3 MW of hydroelectric power, and
approximately 9.8 MW of diesel‐generated power. The existing hydroelectric facilities can
produce enough power to meet community demand except in late winter when Goat Lake has
drained down, and the Kasidaya project is off‐line due to low flows and freezing conditions.
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APC relies on its diesel plants to supplement the hydro projects during these periods and other
times when the hydroelectric projects are off‐line for maintenance or repair.
2.2.3 Electrical Distribution System
The APC is the certificated electric utility in the Skagway area. It is also connected to the Haines
area by a 15‐mile undersea cable. The IPEC provides retail electric power to Klukwan and the
Chilkat Valley near Haines. In addition, the following transmission lines have been built in
Upper Lynn Canal since 2005:
Intertie to Dyea Valley – 2005;
5 mile to 10 mile Haines Highway intertie – 2007;
Intertie from IPEC system to the Canadian Border – 2007;
Intertie to Lutak Community near Haines – 2007;
Power line to the Canadian border station from Skagway; and
Power line from Whitehorse, YT to Carcross, YT.
2.2.4 Future Projects
Since the undersea cable in Taiya Inlet provides most of the renewable power to Haines, that
community would rely mainly on diesel generation should that cable be incapacitated. The
AP&T is looking for hydroelectric potential in the Haines area to reduce that dependence on
diesel generation. Connelly Lake (on the Haines side of Lynn Canal) and Schubee Lake (on the
Skagway side of Lynn Canal) are both being investigated for potential hydroelectric generation.
Both Lake projects are in the process of receiving preliminary FERC permits. Connelly Lake has
the capacity to produce 10 to 15 MW, and Schubee Lake has a 3 to 5 MW capacity. The
Connelly Lake facility could be operational by 2015 or 2016. Schubee Lake would likely not be
operational until 2018 or 2019.
The Municipality of Skagway is investigating the development of a hydroelectric dam project at
West Creek. That facility has the capacity to produce 25 to 50 MW of power in the future. The
intent of this project is to complete transmission lines to connect it to the Canadian electric grid,
and sell power to Canada. No FERC permits have been applied for as yet, and it is unlikely this
facility would be operational before 2017 or 2018.
On the Canadian side of the border, Yukon Energy, the electric utility serving the Yukon
Territory (YT), is developing two small projects near Tutshi Lake south of Carcross, YT. One of
those projects would be a pumped storage project. The current transmission line from
Whitehorse, YT to Carcross, YT ends about 47 miles from the Alaska border. APC’s existing
34.5 kV distribution lines extend to within approximately 7 miles of the Alaska border. This
project would extend the line about 10 to 15 miles closer to the Alaska border, reducing the gap
between the two systems. Yukon Energy has interest in connecting to the Skagway electric grid
in order to purchase power for the increasing mining activity in the Yukon region.1
1 Personal conversation with Hector Campbell, Director of Resource Planning & Regulatory
Affairs, Yukon Energy, Whitehorse, YT, Canada, October 2011.
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2.2.5 Existing Electric Load Profile
Table 2‐4 presents power generation and usage in Haines and Skagway from 2004 through 2010.
While there is more demand for power in the summer because of the increased population and
visitation, there is ample existing hydroelectric generation during the summer season. During
the winter, as Goat Lake drains down, and Kasidaya Creek is off‐line, supplemental energy is
generated with diesel generators.
Table 2‐4: Recent Electric System Statistics
Parameter 2004 2005 2006 2007 2008 2009 2010
kWh Generated 23,907,062 23,931,656 NA 28,020,445 31,738,747 28,309,127 28,251,646
kWh Generated with
Diesel 761,200 189,680 219,160 1,296,970 3,073,780 1,236,110 238,820
(Diesel as % of total
generation) 3.2% 0.8% NA 4.6% 9.7% 4.4% 0.8%
kWh Sold 21,825,252 22,297,987 NA 24,172,427 25,210,170 25,063,025 24,286,111
System Losses
(Generated but not sold) 8.71% 6.83% NA 13.73% 20.57% 11.47% 14.04%
Fuel Price
(annual average) $1.14 $1.61 $2.01 $2.57 $2.84 $2.17 $2.68
Fuel Used (gallons) 60,312 19,081 20,375 90,969 210,423 86,836 18,236
Total Fuel Expense 68,805 30,699 40,915 234,061 596,603 188,049 $48,876
Total Non‐Fuel Expense 995,989 1,276,902 1,007,552 846,263 968,983 1,207,594 $3,060,050
Total Utility Expense $1,064,794 $1,307,601 $1,048,467 $1,080,324 $1,565,586 $1,395,643 $3,108,926
Power Cost per kWh sold $0.02 $0.03 NA $0.02 $0.03 $0.03 $0.06
Diesel Generation
Efficiency (kWh/gal) 12.6 9.9 10.8 14.3 14.6 14.2 13.1
All data is compiled from monthly Power Cost Equalization program records provided by AEA. Data is in state
fiscal years (July 1st through June 30th).
kWh: kilowatt‐hours
gal: gallons
The data above shows that more power is consistently generated by APC than is consumed in
the Haines and Skagway markets. This is due in part to inherent distribution system losses that
are typical of any utility system.
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2.2.6 Projected Future Electric Load Profile
Table 2‐5 presents average population in the project area and kilowatt‐hours (kWh) sold
between 2004 and 2010. An intertie to the Chilkat Valley was completed in 2007, which would
have caused an increase in power usage in that year that would have flattened out in
subsequent years. Even with a growth of population of over 10% between 2009 and 2010,
energy usage dropped by about 3% in that year.
Table 2‐5: Changes in Population and Energy Consumption in Haines and Skagway, 2004 to 2010
Year
Annual Average
Population
Percent
Change kWh Sold Percent
Change
kWh Sold
per Resident
Percent
Change
2004 3,726 ‐0.4% 21,825,252 5,858
2005 3,615 ‐3.0% 22,297,987 2.2% 6,168 5.3%
2006 3,677 1.7% 23,168,671 3.9% 6,301 2.2%
2007 3,669 ‐0.2% 24,172,427 4.3% 6,588 4.6%
2008 3,732 1.7% 25,210,170 4.3% 6,755 2.5%
2009 3,728 ‐0.1% 25,063,025 ‐0.6% 6,724 ‐0.5%
2010 4,121 10.6% 24,286,111 ‐3.1% 5,893 ‐12.4%
Sources: Alaska Department of Labor and Workforce Development, and Alaska Energy Authority Power
Cost Equalization Program reports.
kWh: kilowatt‐hour
Note: An intertie to the Chilkat Valley was completed in 2007. This connection would have caused an
increase in power usage that would have flattened out in subsequent years.
According to the population projections produced by the Alaska State demographer’s office,
population is expected to decline by an average annual rate of 1.8% in the Haines Borough
between 2009 and 2034. Population projections were not developed for the Municipality of
Skagway alone, and the communities combined with Skagway in the projections that were
developed are so economically and demographically different from Skagway, that this data is
not useful for an analysis of future population changes in that community. However, it is likely
that Skagway’s future population will not decline as rapidly as is projected for the Haines
population.
Cruise ship traffic had been on a slight decline, but is expected to begin increasing again in 2012.
However, Skagway has a small port area, and is nearly at capacity for the number of ships it can
host each day. There is room for growth in cruise ship traffic at Haines, however.
Increased energy efficiency and conservation puts downward pressure on growth of energy
demand. As a result of the slowing population growth, slowing per capita energy
consumption, and possible slow growth in visitors to the area, growth in energy demand is
expected to decline slightly.
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Three potential future occurrences in the project area could put additional loads on energy
demand. Two of those occurrences are somewhat linked to development of additional
alternative energy resources, and one may be influenced by addition of those resources.
Yukon Energy is facing growing power demand from mining projects in the Yukon
Territory. The company is developing two small projects near Tutshi Lake south of
Carcross, YT, one of which is a pumped storage project. That development would bring
power lines capable of transmitting 5 to 10 MW of power to within about 35 miles of the
Alaska border, which is near the existing limit of APC’s Skagway distribution system.
Burro Creek power would work well with the planned pumped storage project at Tutshi
Lake, and Yukon Energy has expressed interest in continuing its transmission lines to
the Alaska/Canada border to connect with the Skagway grid in order to purchase all of
the power produced by Burro Creek (at $0.10 to $0.15 per kWh) 2. If the Municipality of
Skagway’s West Creek or other hydroelectric power developments occur, this
transmission connection could be improved to carry more energy into Canada.
With development of the Connelly and/or Schubee Lake hydroelectric facilities
(operations beginning as early as 2016), APC would likely develop shore power
hookups for cruise ships at Skagway. Under this scenario, it is possible that APC would
purchase all of Burro Creek’s power during the cruise ship season (about 20 weeks
beginning in mid‐May, and ending in mid to late‐September). This would be a
substantial portion of Burro Creek’s annual output (8,410,000 kWh, or 58% of the annual
output from a 3.4 MW project, configuration 3D‐70).
With development of the Palmer mine project north of Haines, demand for power will
increase significantly, and APC would likely purchase all the power that Burro Creek
could produce year around. If the results of ongoing mineral exploration are favorable,
mine construction could begin in 2020, with the mine becoming operational in 2022.
Power demand during construction is assumed to be about 2 MW, increasing to about 4
MW when operations begin. Development of this mine is dependent upon mineral
prices and other variables.
A forecast of future electric demand in the Haines and Skagway area is based on existing and
expected future trends in population and energy consumption growth, and considers potential
future development that will impact energy demand. Table 2‐6 and Figure 2‐1 present a 50‐year
forecast of energy demand growth in the Haines/Skagway areas under several scenarios. The
load growth associated with a connection to the Yukon Electric grid is not quantified in this
study, as the Yukon Energy grid is substantially larger than the Upper Lynn Canal grid, and a
connection to the Yukon Energy grid is assumed to provide a market for the entire output of a
Burro Creek project.
2 Personal conversation with Hector Campbell, Director of Resource Planning & Regulatory
Affairs, Yukon Energy, Whitehorse, YT, Canada, October 2011.
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Table 2‐6: Haines/Skagway Electrical Demand Forecast, 2012 to 2062
Normal Load Scenario
Year low Moderate high Moderate with
Cruise Ships
Moderate
with Mine
Moderate
with Both
2012 24,286 24,286 24,286 24,286 24,286 24,286
2017 23,096 23,685 24,899 69,045 23,685 69,045
2022 21,964 23,099 25,528 68,459 58,139 103,499
2027 20,887 22,527 26,173 67,887 57,567 102,927
2032 19,864 21,969 26,833 67,329 57,009 102,369
2037 18,890 21,426 27,511 66,786 56,466 101,826
2042 17,964 20,895 28,206 66,255 55,935 101,295
2047 17,084 20,378 28,918 65,738 55,418 100,778
2052 16,247 19,874 29,648 65,234 54,914 100,274
2057 15,450 19,382 30,397 64,742 54,422 99,782
2062 14,693 18,902 31,164 64,262 53,942 99,302
Source: Southeast Strategies, October 2011. All units are annual megawatt‐hours.
Table 2‐6 and Figure 2‐1 incorporate the following assumptions:
● Under the Normal Load Scenario, the low growth forecast assumes a drop in energy
demand of 1% per year due to forecasted declining population, and increased energy
efficiency from improved technology.
● Under the Normal Load Scenario, the moderate growth forecast assumes a drop in
energy demand of 0.5% per year due mainly to increased energy efficiency from
improved technology, and assumes only a slight drop in population.
● Under the Normal Load Scenario, the high growth forecast assumes an increase in
energy demand of 0.5% per year due mainly a slight increase in population and business
activity in the area.
● The Moderate Growth Forecast with Cruise Ships scenario assumes the moderate
growth forecast for the normal energy load, with the development of shore power hook
ups for cruise ships in Skagway beginning in 2017. This scenario assumes an average of
3 ships per day tying into shore power for 12 hours per day, for 140 days. This forecast
assumes each ship requires an average of 9 MW of power, and the total additional
power demand per season would equal 45,360 MWh.
● The Moderate Growth Forecast with Mine scenario assumes that the Palmer mine north
of Haines will be developed, and connect to the power grid at Haines. It is assumed that
construction of the mine begins in 2020, and continues for two years. Mine operations
would begin in 2022, and continue at a steady pace through at least the end of the
forecast period. That load was added to the moderate growth forecast for the normal
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energy load for this scenario. Mine operations are assumed to require an average of 4
MW year around (the Kensington Mine north of Juneau currently uses 6 to 7 MW year
around), with half that load used during the construction phase (2020 and 2021).
Figure 2‐1: Haines/Skagway Moderate Electrical Demand Forecast, 2012 to 2062
Source: Southeast Strategies, 2011.
MWh: megawatt‐hours.
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3.0 HYDROELECTRIC DEVELOPMENT OPTIONS
3.1 RESOURCE DESCRIPTION
Burro Creek is located approximately two miles southwest of Skagway, Alaska (Figure A‐1).
The Burro Creek basin is in a transitional area between the moderate maritime climate of
southeast Alaska and the more extreme continental climate of the Yukon. Annual precipitation
in the Burro Creek basin is estimated at 80 inches, based on measured Burro Creek flows and
large‐scale isohyetal maps of Alaska. Total annual precipitation in Skagway is 26 inches. The
difference between measured precipitation in Skagway and estimated precipitation in the Burro
Creek basin is attributed to orographic effects that result in micro‐climate variations (rain
shadows, etc.) in the area’s mountainous terrain 3.
Burro Creek drains an east‐facing basin running on a southeast – northwest axis that is 2 to 3
miles wide and 5.5 miles long, totaling approximately 12 square miles in area. The basin
extends from tidewater on Lynn Canal up to a series of 4,500 to 5,500 foot peaks to the north
and 4,000 to 4,500 foot peaks to the south. Prominent peaks include Face Mountain (4,830 feet),
Parsons Peak (5,600 feet+), and Mount Harding (5,321 feet). Several other peaks 4,000 to 5,500
feet in elevation surround the basin. The basin has little to no glaciation, and is forested to an
elevation of approximately 3,000 feet. The basin is bordered by West Creek, a tributary of Taiya
River, to the north, and by Ferebee River to the west and south. Minor drainages discharging
directly to Lynn Canal are located northeast and southeast of the Burro Creek basin. The basin
is mountainous, with little evidence of extensive alluvial or fluvial deposits except along the
valley bottom where Burro Creek flows. Bedrock is visible at the surface in many areas.
The lower approximately 3,550 feet (0.67 miles) of Burro Creek is located on USS 1560, a 121‐
acre property owned by Burro Creek Holdings, LLC. The upper reach of Burro Creek to its
headwaters is located on Federal land managed by the Bureau of Land Management (BLM).
From tidewater up to mile 0.13, Burro Creek runs at a gradient of approximately 7% over a
combination of exposed bedrock, cobbles, and boulders. There is an approximately 15‐foot
waterfall at mile 0.13 (Photograph B‐2). From mile 0.13 to 0.42, the creek gradient is
approximately 12%. At mile 0.42, there is a diversion structure for the existing small hydro
plant at an elevation of 235 feet at the head of a series of rock sills that Burro Creek cascades
down (Photograph B‐6). Between this diversion structure and the westerly property line, Burro
Creek runs at approximately 8%, rising to an elevation of 340 feet at the westerly USS 1560
property line. The creek cascades over large boulders and cobbles throughout this reach
(Photograph B‐15). Upstream from the property line, Burro Creek runs at approximately 10% to
mile 1.00 (elevation 500 feet), then at 5 to 8% to mile 2.58 (elevation 1,160 feet). Major tributaries
flow into Burro Creek between mile 2.58 and 2.74. Above these, Burro Creek continues for
approximately six more miles to its alpine headwaters. The reach from mile 2.58 down to
tidewater, or a subset thereof, is of interest for hydropower development.
3 Precipitation data and sources are discussed in Section C.1 of Appendix C.
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3.2 OVERVIEW OF PROJECT CONFIGURATIONS CONSIDERED
The Burro Creek basin lacks any notable dam sites suitable for significant storage reservoirs.
While dams may be technically feasible at Burro Creek, the cost of a dam is expected to be out
of proportion to the value of the resulting storage and hydropower regulation for a project large
enough to export power to the Upper Lynn Canal market. Accordingly, this study only
considers run‐of‐river hydropower options at Burro Creek.
Several potential diversion sites, powerhouse sites, and design flows were evaluated for Burro
Creek. These are summarized in Table 3‐1 and discussed in Appendix G. The five different
diversion locations, numbered 1 through 5, are shown on Figures A‐2, A‐3, and A‐4 in
Appendix A. The four different powerhouse locations, numbered A through D, are shown in
Figure A‐3.
Table 3‐1: Project Configurations Considered
Parameter Values Considered
Diversion Location
1. 1,160 foot elevation
2. 1,000 foot elevation
3. 800 foot elevation
4. Property Line (340 foot elevation)
5. Existing Diversion (235 foot elevation)
Powerhouse Location
A. Existing Powerhouse (33 foot elevation)
B. Below Falls (50 foot elevation)
C. Above Falls (80 foot elevation)
D. North of Dock (50 foot elevation)
Design Flow
50 cfs (30‐inch penstock)
70 cfs (36‐inch penstock)
110 cfs (42‐inch penstock)
CONFIGURATION
CODES AND
NOMENCLATURE
For brevity, project configurations in this report are referenced in
shorthand. Configuration ‘3D‐70’ references a project with a diversion at
site ‘3’, a powerhouse at site ‘D’, and a design flow of 70 cfs.
Source: Polarconsult Alaska, Inc., 2011.
3.3 RECOMMENDED PROJECT CONFIGURATIONS
Combinations of the project parameters listed in Table 3‐1 were analyzed for estimated cost,
estimated energy generation, and environmental issues. To a significant degree, the most
favorable project configuration at Burro Creek will depend on the needs of the market that the
project is built to serve. This section presents project configuration ‘3D’ with a design flow of 70
cfs (referred to as configuration ‘3D‐70’), which has the lowest estimated sales price of power,
assuming all project output is sold and no grants are used for the project’s development costs.
Several other project configurations have similar estimated sales prices as configuration 3D‐70,
and are also technically similar to 3D‐70. Other project configurations are discussed in
Appendix G, and estimated costs and energy sales prices for other project configurations are
presented in Appendix H. Table H‐2 provides estimated energy sales prices for a selection of
project configurations, financing scenarios, and market scenarios.
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Project configuration 3D‐70 has an intake at 800 feet elevation (site 3) and a design flow of 70
cubic feet per second (cfs). The estimated sales price for energy generated by this project
configuration, assuming the full output is sold, is approximately 12 cents per kWh, using the
financial assumptions described in Appendix H.
At this level of analysis, the cost of power for this project configuration is essentially the same
for the four powerhouse sites considered in this study. The differences in penstock length and
total project head between the various powerhouse sites amounts to less than 5% variation in
the estimated sales price, which is within the margin of error of this study.
Because the market for power from this project is not well defined at this time, there is latitude
to tailor the project to the needs of the customer. The full range of project configurations
outlined in Table 3‐1 have installed capacities ranging from 430 kW up to 7.3 MW, and average
net annual energy output from 2,041,000 kWh to 20,581,000 kWh. This detailed information in
provided in Table H‐2 of Appendix H.
3.4 ESTIMATED ENERGY GENERATION
The installed capacity of configuration 3D‐70 is 3.4 MW, and the estimated annual net energy
generation for the recommended project is 13,127,000 kWh, for a capacity factor of 44%. Figure
3‐1 presents the estimated seasonal distribution of this energy output. Seasonal energy output
for other project configurations is presented in Table H‐2 of Appendix H.
Figure 3‐1: Estimated Average Annual Net Output of Project 3D‐70
Source: Polarconsult Alaska, Inc., 2011.
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecEstimated Average Daily Project Net Power Output (kW)0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
Estimated Average Daily Net Energy Generation (kWh)Estimated Average Daily Net
Power Output (kW)
Estimated Average Daily Net
Energy Generation (kWh)
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November 2011 – Final Report 18
3.5 DESCRIPTION OF PROJECT FEATURES
Key features of project 3D‐70 are described in the following sections.
3.5.1 Transmission Line
A transmission line is required to get the output of the Burro Creek project to markets in
Skagway or beyond. Four potential transmission line configurations were evaluated for this
study, and are described in Appendix G, section G.3. The most economical transmission line is
a submarine cable routed from Burro Creek to Skagway. All project configurations discussed in
this study include the cost of a transmission line to Skagway, but do not include other
transmission line upgrades or extensions (e.g., from the APC system north to Carcross).
The submarine cable route from Burro Creek to Skagway is shown on Figure A‐5 in Appendix
A. The route is approximately 2.2 miles long, and has a maximum depth of approximately 600
feet. The submarine cable installation would consist of four individual cables, three cables for
the power intertie and a fourth cable as a spare in the event one of the three in‐service cables
fails. This approach is preferred over a single bundled cable, as the cables can be individually
laid by smaller vessels available on the west coast of North America. A bundled cable would
likely require mobilization of a more specialized cable laying ship from Asia or Europe, which
is expected to be prohibitively expensive for this project. Also, in the event of a cable failure, a
single failed cable will be easier to lift off the bottom of Lynn Canal for repair than a bundled
cable.
The cables would be a jacketed full concentric neutral power cable with 1/0 conductor insulated
for 25 kV AC service. The intertie would operate at a voltage of 24.9 kV. Cable armor would be
required at the shore ends to protect from abrasion due to wave action. More study would be
necessary to determine if cable armor is necessary along the entire cable route. Currents,
bottom conditions, commercial fishing activity, and marine practices (anchoring) would all be
determinants in whether armor is needed for the submarine cables. The feasibility cost
estimates assume armor is provided only for the 800 feet of cable nearest to shore at each end.
3.5.2 Controls and System Integration
Because Burro Creek is only approximately 2 miles line‐of‐sight from Skagway, a dedicated
secure radio communications link is suitable for communications between the Burro Creek
project and the APC system. As would be defined in the power sales agreement between BCH
and APC, APC would have the ability to control project output as part of overall management
and operation of generation assets serving the Upper Lynn Canal grid.
Burro Creek operations would be controlled by an on‐site control system that would monitor
flow in Burro Creek and regulate power generation accordingly. Control and power circuits
would be run along the penstock route from the power house up to the diversion/intake site to
monitor conditions at the intake and actuate gates and related equipment to maintain the intake
system in an operational condition.
The hydro turbine would be regulated by spear valves, unlike the existing Burro Creek project
which is regulated by deflector control. Spear valve regulation would enable the larger project
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November 2011 – Final Report 19
to operate at low flows. This is not an issue for the existing project, which has adequate flow to
use deflector control for frequency regulation.
3.5.3 Access and Staging
All construction equipment, material, supplies, and personnel would arrive at Burro Creek by
barge. The existing landing area is adequate for landing construction materials and equipment.
Existing cleared areas at Burro Creek are likely adequate for project staging. If not, staging
could also occur in Skagway, or additional staging areas could be cleared to the north of the
existing dock. There is adequate space in this area to maintain a vegetated buffer along the
shore to screen staging activities from view along Lynn Canal.
Existing trails on USS 1560 extend up towards the existing intake at elevation 235 feet. These
trails would be improved to provide for equipment access for construction of this project.
Terrain above the existing intake is favorable for construction of trails up to the westerly
property line of USS 1560. Above the property line, the terrain becomes steep, and significant
trail‐building work will be necessary to side‐hill a bench up to the intake site. Side slopes are
consistently 50 to 100% for approximately 3,500 feet of the penstock / access route through this
area. Due to the prevalence of shallow bedrock in this area, significant blasting will be required
to establish an access trail and penstock bench. Because of the location up in Burro Creek
valley, this access route and penstock bench will not be visible from Skagway but will be
partially visible to ship traffic on Lynn Canal. It will be visible from the air.
3.5.4 Construction Schedule
Construction is scheduled to occur over two seasons. The first construction season would focus
on building the access trail up to the intake, building the powerhouse and tailrace, and
installing the penstock.
The second construction season would start with construction of the in‐stream diversion
structure in March. This would coincide with a period of reliable low flow in Burro Creek,
simplifying the in‐stream construction work for the diversion structure. During the summer,
the penstock would be installed, the submarine cable would be laid, and the turbine/generator
equipment would be installed in the powerhouse.
Construction would be completed and the project commissioned in the fall of the second
construction year.
3.5.5 Intake
While there are numerous exposed bedrock sills on the lower reaches of Burro Creek between
tidewater and the existing intake at mile 0.42, there does not appear to be any exposed bedrock
in Burro Creek above the vicinity of the existing intake. This conclusion is based on field
investigations up to the 700 foot elevation and review of aerial imagery up to the 1,160 foot
elevation. Throughout the reach from mile 0.42 up to mile 2.58 (which includes conceptual
intake sites 1, 2, 3, and 4), Burro Creek cascades over cobbles and boulders at gradients of 5 to
10%. No notable features were identified in this reach that present especially favorable intake
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sites. However, there are three apparent avalanche hazard areas in this reach where project
intakes should not be built. These are approximately located from mile 1.23 to 1.36, from mile
2.06 to mile 2.12, and from mile 2.18 to mile 2.41 along Burro Creek. All of these avalanche
chutes extend down from the south side of Burro Creek, whereas the penstock would be located
on the north side of Burro Creek.
The conceptual diversion and intake structure design for a project with an intake at sites 1, 2, 3,
or 4 (or in between these locations) calls for a reinforced concrete wall founded on alluvium and
buttressed with local fill. If geotechnical investigations identify shallow bedrock at the intake
site, that would be advantageous for foundation design and also sealing off subsurface flow.
The intake would incorporate Obermeyer‐type gates to pass debris and flood flows, and would
feature a protected forebay to divert project flows from the main channel of the creek to a
coanda‐type inclined screen intake structure to screen water and admit it to the penstock.
3.5.6 Penstock
The penstock for configuration 3D‐70 would be an approximately 7,600 foot long, 36‐inch
diameter pipeline. The first approximately 5,000 feet of pipe would be relatively low pressure
(under 100 psi static pressure), and can be constructed of HDPE or PVC pipe. The last
approximately 2,600 feet of pipe would be higher pressure (100 to 330 psi static pressure), and
would be constructed of steel pipe.
The pipe can be installed above ground or buried. This will depend on the geotechnical
conditions along the penstock / access route, and the final design and configuration of the
intake bench. A buried pipeline would be more protected from cold weather and potential
damage from tree falls. Above ground pipes of this diameter have little risk of freezing in
southeast Alaska provided the water is kept moving through the pipe. If the project is off line
in the winter months, the penstock should be drained or allowed to keep flowing through a
bypass valve at the powerhouse.
Penstocks for other project configurations would be similar as that for configuration 3D‐70 as
described above. The diameter, length, and transition points between materials and pipe walls
would vary as dictated by the technical details of the particular configuration.
3.5.7 Powerhouse and Tailrace
The powerhouse would be an approximately 36‐foot by 36‐foot building housing the turbine,
generator, switchgear, and controls for the project. The powerhouse is assumed to be sited at
the location of the existing project powerhouse, but can be moved to any of the other three sites
listed in Table 3‐1 with a very modest impact on project performance or economics.
The turbine would be a two‐jet Pelton turbine fitted with spear valves for power and frequency
regulation. The Pelton wheel would be approximately 30 inches in diameter and would drive a
720 rpm synchronous generator.
The tailrace would be an open ditch armored with local cobbles and boulders returning water to
Burro Creek just above tidewater.
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4.0 MARKET ANALYSIS AND OPPORTUNITIES
4.1 MARKET FOR POWER
Currently, APC has slight excess hydroelectric capacity in summer, and not quite enough
hydroelectric capacity in winter for the communities they serve. In recent years, power demand
on the APC system has declined slightly, likely due to a slight decline in visitors to the area and
an increase in energy efficiency. While there are a number of existing opportunities for sale of
Burro Creek power, these existing opportunities do not amount to a market for the full output
of a project at Burro Creek. These existing opportunities are discussed in Section 4.1.1.
There are several emerging developments within the Upper Lynn Canal region that could buy
the full output of a Burro Creek project. These emerging opportunities include cruise lines
wanting to use shore power while in port at Skagway, the Palmer Project mining prospect north
of Haines, and the Canadian power grid if an intertie is built. These opportunities have
development schedules that are similar to the schedule for Burro Creek, and are discussed in
Section 4.1.2.
Section 2.2.6 presents long‐term energy forecasts under a variety of growth and large project
scenarios. The load growth associated with a connection to the Yukon Electric grid is not
quantified in this study, as the Yukon Energy grid is substantially larger than the Upper Lynn
Canal grid, and a connection to the Yukon Energy grid is assumed to provide a market for the
entire output of a Burro Creek project.
4.1.1 Existing Market Opportunities
Without future development of new markets for power in Upper Lynn Canal (discussed in
Section 4.1.2), it would be possible for Burro Creek to sell power in a few instances. At this
time, these opportunities are a viable market for only a portion of the output of Burro Creek.
These opportunities are:
The APC generates an average of 900,000 kWh of electricity by burning diesel fuel each
year. This mostly occurs in late winter, when their hydroelectric facilities are shut down
for maintenance and repairs. The APC may purchase Burro Creek power during those
times, especially in late winter, when Goat Lake has drained down, and Kasidaya Creek
is still frozen to avoid diesel generation. Late winter power purchase could amount to
up to 20 days per year. Unfortunately, this is the time of year that Burro Creek has a
low flow, so does not produce a lot of power. Representatives of APC estimated their
avoided cost of diesel generation in the Haines‐Skagway area at about $0.28 per kWh.
That rate will vary with changes in the price of diesel fuel.
The IPEC may purchase Burro Creek power if the cost is less than the APC power it
currently purchases (about 241,000 kWh per year at about 12.35 cents per kWh).
However, IPEC continues to acquire and develop its own sources of power, so may not
need Burro Creek power in the long term. APC would charge BCH a fee to move energy
across APC’s distribution system (called ‘wheeling’). This fee is estimated at two cents
per kWh.
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November 2011 – Final Report 22
Burro Creek can sell power to businesses with a common owner without having to
become a certified utility. In the past year, businesses held in common with the owner
of BCH used about 110,000 kWh of power. Businesses are not eligible for Power Cost
Equalization subsidies, so this power was charged at the rate of around $0.21 per kWh.
APC would charge BCH a wheeling fee of about two cents per kWh to deliver this
power to the businesses held in common.
If Burro Creek’s sales price of power is less than AP&T’s cost to produce power, then
APC may be willing to enter into a wholesale power sales agreement to purchase
additional power from Burro Creek. However, APC has a ‘take or pay’ agreement with
AP&T for the full output of AP&T facilities on the Upper Lynn Canal grid, to the extent
that all AP&T costs (including debt service) are covered. This agreement applies to the
Goat Lake and Kasidaya hydro projects, and runs until construction bonds on these
projects are retired in the late 2030s. APC would not be able to purchase large amounts
of Burro Creek power before about 2040 unless regional demand increased beyond the
capacity of AP&Ts existing facilities. Current charges for APC power in the Haines-
Skagway area is about $0.21 per kWh. Residential and community facility customers
receive a subsidy of about $0.07 per kWh through PCE.
4.1.2 Potential Future Market Opportunities
Several development projects in the Upper Lynn Canal region would significantly increase
demand for electrical power generation, creating a good market for the output of Burro Creek.
Yukon Energy is facing growing power demand from mining projects in the Yukon
Territory. The company is developing two small projects near Tutshi Lake south of
Carcross, YT, one of which is a pumped storage project. That development would bring
power lines capable of transmitting 5 to 10 MW of power to within about 42 miles of the
existing limit of APC’s 34.5 kV distribution system north of Skagway. Burro Creek
power would work well with the planned pumped storage project at Tutshi Lake, and
Yukon Energy has expressed interest in extending its transmission lines south to the
Upper Lynn Canal system in order to purchase all of the power produced by Burro
Creek (at $0.10 to $0.15 per kWh) 4. If the Municipality of Skagway’s West Creek or
other hydroelectric power developments occur, that transmission line could be
improved to carry more energy into Canada.
With development of the Connelly and/or Schubee Lake hydroelectric facilities
(operations beginning as early as 2016), APC would likely develop shore power
hookups for cruise ships at Skagway. Under this scenario, it is possible that APC would
purchase all of Burro Creek’s power during the cruise ship season (about 20 weeks
4 Personal conversation with Hector Campbell, Director of Resource Planning & Regulatory
Affairs, Yukon Energy, Whitehorse, YT, Canada, October 2011. See correspondence in
Appendix K.
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November 2011 – Final Report 23
beginning in mid‐May, and ending in mid to late‐September). This would be between
71 and 81% of Burro Creek’s annual output, depending on the project configuration.
With development of the Palmer mine project north of Haines, demand for power will
increase significantly, and APC would likely purchase all the power that Burro Creek
could produce year around. If the results of ongoing mineral exploration are favorable,
mine construction could begin in 2020, with the mine becoming operational in 2022.
Power demand during construction is assumed to be about 2 MW, increasing to about 4
MW when operations begin. Development of this mine is dependent upon mineral
prices and other variables.
4.2 PROJECT COST ESTIMATES
Appendix H presents estimated capital costs for 15 different project configurations at Burro
Creek. The 15 configurations include three different design flows (50 cfs, 70 cfs, and 110 cfs) at
five different diversion elevations. The capital cost estimates for these project configurations
range from $4,342,000 to $21,069,000, and in all cases include a transmission line to Skagway.
Appendix H also provides estimated annualized costs for these project configurations,
including debt service, maintenance, operations, and periodic replacement and refurbishment
ranging between $437,000 and $4,082,000.
4.3 POTENTIAL BURRO CREEK BUSINESS OPPORTUNITIES
Appendix H develops cost estimates for various project configurations, as well as estimated
power output, financing scenarios, and estimated sales prices (cents per kWh) required for each
configuration. For each project configuration, scenarios were developed for partial power sales,
and sales of the full output of each project.
Projects producing a base power cost of about $0.10 per kWh and lower would allow Burro
Creek power to be competitive in current markets such as wholesale to IPEC, and sales to
business held in common. For both of those power markets, a $0.02 per kWh wheeling charge
for use of APC transmission lines would be added to the base charge, bringing the highest
feasible power costs to about $0.12 per kWh to the consumer. If a wholesale purchase
agreement with APC could be developed, a wheeling charge would be unnecessary, and
projects with slightly higher kWh costs would be feasible. However, as APC has been hesitant
to state conditions and costs at which they would be willing to purchase power from Burro
Creek, it is difficult to determine which project configurations would be feasible if such an
agreement could be reached.
Because it is unlikely that Yukon Energy would consider building a transmission line
connecting its grid to the Upper Lynn Canal system without a promise of sales of at least 4 MW
in capacity, the proposed projects were narrowed to only those with an installed capacity of
over 4 MW. However, smaller projects may also be feasible if a connection to the Canadian grid
is not developed, as long as those project costs remained below $0.10 per kWh, or a wholesale
power purchase agreement with APC could be reached. None of the projects analyzed in
Appendix H would have costs at or below $0.10 per kWh unless some grant funding for those
projects can be obtained.
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November 2011 – Final Report 24
Table 4.1 shows that, provided grant funding can be found for these four projects with installed
capacities of over 4 MW, they would produce power for a low enough cost to be attractive to
Yukon Energy. Representatives of Yukon Energy stated that they would purchase power for
between $0.10 per kWh and $0.15 per kWh.
Table 4‐1: Comparison of Potential Project Costs and Required Power Prices Projects Over 4
MW in Capacity
Project Configurations
1D‐70 1D‐110 2D‐110 3D‐110
Installed Capacity (kW) 4,400 7,300 6,500 5,250
Avg. Ann. Net Energy Output (MWh) 17,943 20,581 18,798 15,915
Estimated Capital Costs $17,229,000 $21,069,000 $16,750,000 $13,765,000
Estimated Required Power Sales Rate with 50% Grant Funding * ($/kWh)
50% Grant – Full Year Sales** $0.102 $0.113 $0.097 $0.095
Source: Polarconsult Alaska, Inc., October 2011.
* Grant funding is capped at $8,500,000.
** The estimated power sales rate includes a $0.02 per kWh wheeling charge for use of APC
transmission lines.
4.4 OTHER INTANGIBLE PROJECT BENEFITS
In addition to the obvious monetary benefits to the power producer, the Burro Creek
hydroelectric project provides benefits to the public, including:
This completed facility will provide a reliable additional source of renewable energy that
can be used to replace diesel generation when other hydroelectric facilities on the grid
are not operable.
The completed facility could replace cruise ship generator power with shore power,
reducing air emissions in the Skagway area in the summer season.
The completed facility will increase the reliability of power generation in the Upper
Lynn Canal region.
Construction of this project will provide short term jobs in the area during construction,
and a variety of employment opportunities over the long term for management,
maintenance, operations, and repairs.
Economic multipliers in the local economy due to the fact that more energy will be
generated from local resources and local labor vs. imported diesel or bunker fuels.
Secondary benefits from having more stably‐priced hydropower on the local utility grid.
Reduced volume of hydrocarbon fuels being barged through the waters of Southeast,
reducing the probability of fuel spills.
This project fits well within the criteria for beneficial projects as evaluated by the Alaska Energy
Authority.
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November 2011 – Final Report 25
5.0 CONCLUSIONS AND RECOMMENDATIONS
There is a viable run‐of‐river hydroelectric resource at Burro Creek. A range of project
configurations all using Federal land above BCH property appear to be viable provided a
market develops for the power they would produce. These projects have capacities of 3.4 to 7.3
MW and annual generation potential of 13,127 to 20,581 MWh. The specific project
configuration that warrants development will depend on the needs of the market it would
serve. Capital cost estimates and some financial scenarios for select project configurations are
presented in Appendix H.
If the entire output of the most economical project configuration (Configuration 3D‐70) can be
sold, the sales price is estimated at 12 cents per kWh, assuming a debt‐financed project.
Different business models or equity structures would result in higher or lower energy pricing.
At this time, there is not a market for the full output of a project at Burro Creek of this size.
Smaller projects down to the existing 15 kW project are also technically viable, however they
would require higher per kWh sales prices to be economically viable for sale to the Upper Lynn
Canal market. There are a number of emerging market opportunities in the Upper Lynn Canal
region that may present a market for the full output of Burro Creek, and that have similar
development schedules as a Burro Creek project.
Because the market for the output of this project is still developing, there is some latitude to
tailor the installed capacity of the project to market demand. This can be accomplished by
adjusting the diversion location and/or the design flow, as neither parameter is strongly
constrained by the characteristics of the resource at Burro Creek.
5.1 DEVELOPMENT PLAN & SCHEDULE
The estimated development schedule for a Burro Creek project is summarized in the following
figure. Figure 5‐1 assumes that a market for the power is secured in the first half of 2012 to a
degree that justifies expenditure of pre‐development costs. Based on assessment of the current
market, this is an ambitious goal that depends on the outcome of future discussions between
BCH and potential customers as discussed in Section 4. If securing a buyer for the project
output is delayed, the remainder of the development schedule will be extended forward in
time.
Based on available data, the project can be operational in as little as 5 years after a buyer for the
project output is secured and a ‘go’ decision is made for the project. This is based on either use
of the FERC Integrated Licensing Process or obtaining a FERC exemption from licensing, and a
two‐year construction schedule. Complications in the permitting, financing, or construction
phases of project development could result in delays in this project development schedule.
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November 2011 – Final Report 26
2009 2010 2011 2012 2013 2014 2015 2016
ACTIVITY 12341234123412341234123412341234
Feasibility Study
Business Plan
Conceptual Design
Permitting
Resource Studies
FERC Exemption
Project Design
Construction Plan
Financing Plan
Construction
Project Commissioning
Construction Phase Close‐out
Figure 5‐1: Project Development Schedule
5.2 RECOMMENDATIONS FOR IMPLEMENTATION
The following actions are recommended to continue advancing Burro Creek, and to position
Burro Creek for development as these emerging markets mature:
Contact the Regulatory Commission of Alaska (RCA) to determine how best to move
forward. The RCA governs sales of power in Alaska, and it is important to understand
the conditions under which a company can sell power to various customers. In general,
an independent power producer such as Burro Creek cannot sell to more than 10
customers or over $50,000 worth of power per year without becoming a certified utility.
In addition, RCA generally will not allow two certified utilities within one service area
However, the RCA Commissioners have the final say on such projects, and can make
exceptions to their regulations as they determine is in the public interest. Appendix F
contains the Alaska Statute language that is pertinent to this project.
Continue stream gauging at Burro Creek to characterize the resource potential.
Monitor future land use planning and management decisions for the BLM land west of
Burro Creek to insure future management decisions do not preclude development of a
hydro project in this area.
Maintain Burro Creek as a generation resource in regional energy planning documents,
such as the Southeast Alaska Integrated Resource Plan, currently under development by
the AEA.
Contact Yukon Energy to discuss the possibility of that company extending its power
transmission line south to the Upper Lynn Canal system, and a possible power purchase
agreement.
Contact the developers of the Palmer Mine to monitor the progress of that project, and if
and when development is assured, to discuss possible power purchase agreements.
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November 2011 – Final Report 27
Contact APC to discuss the conditions under which they may be willing to purchase
wholesale power from BCH.
Contact IPEC to discuss a possible power purchase agreement, keeping in mind that
other market opportunities may need to exist in order to make this market viable.
Contact possible funding sources to identify grants and loan programs that may reduce
the cost of energy from the Burro Creek project.
Burro Creek Holdings, LLC
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November 2011 – Final Report 28
Burro Creek Holdings, LLC
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APPENDIX A – MAPS AND FIGURES
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Figure A‐1: Project Overview and Location Map
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Figure A‐2: Potential Diversion Sites and Drainage Basins
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Figure A‐3: Map of Project Configurations on USS 1560
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Figure A‐4: Map of Project Configurations Using Federal Lands
(Section Line)
PENSTOCK ROUTES
USS 1560
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Figure A‐5: Map of Transmission Routes
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APPENDIX B – PHOTOGRAPHS
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Photograph B‐1: Burro Creek
Site from Lynn Canal
Photograph B‐2: Burro Creek
Waterfall, Looking Upstream
Photograph B‐3: Burro Creek
Gauging Station, Looking
Downstream
View of USS 1560 looking northwest
from Lynn Canal. The main cabin and
outbuildings are visible near tidewater.
The stilling tube that houses the pressure
transducer is visible in this view. A
flexible metal conduit housing the power
cable/ vent tube extends up from the
stilling tube towards the log crib where
the data logger is mounted. The conduit
is anchored to bedrock. Burro Creek is
flowing at 70 cfs in this photo.
May 10, 2010. Polarconsult.
This waterfall is located at mile 0.15 of
Burro Creek. Burro Creek is flowing at
70 cfs.
May 11, 2010. Polarconsult.
Burro Creek Holdings, LLC
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Photograph B‐4: Existing Burro
Creek Intake, Looking Upstream
Photograph B‐5: Existing Burro
Creek Intake Screening Box
Photograph B‐6: Existing Burro
Creek Intake
View of existing screening box looking
upstream.
December 16, 2009. Polarconsult.
View at the existing hydro intake on Burro
Creek at the 235‐foot elevation. The
diversion structure is a log pinned into
bedrock at the head of a series of rock chutes
and cascades. The existing diversion and
intake is past its serviceable life and requires
repair or replacement.
Burro Creek is flowing at 11 cfs.
December 16, 2009. Polarconsult.
View of existing diversion structure
during summer. Burro Creek is flowing
at 70 cfs.
May 10, 2010. Polarconsult.
Burro Creek Holdings, LLC Burro Creek Hydroelectric Study Polarconsult Alaska, Inc. November 2011 – Final Report B‐3 Photograph B‐7: Burro Creek from Skagway BURRO CREEK
Burro Creek Holdings, LLC Burro Creek Hydroelectric Study Polarconsult Alaska, Inc. November 2011 – Final Report B‐4 Photograph B‐8: Burro Creek Gauging Station View of Burro Creek gauging station and creek section to bank full flow. Burro Creek is flowing at 70 cfs. May 10, 2010. Polarconsult. View of Burro Creek gauging station and creek section to bank full flow. Burro Creek is flowing at 70 cfs. May 10, 2010. Polarconsult.
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Photograph B‐9: Typical
Terrain and Vegetation in
Project Area
Photograph B‐10: Existing
Penstock
Foot path to the existing intake
from the dock. This terrain and
vegetation is representative of
conditions on USS 1560 where
access trails or penstocks would be
located.
May 11, 2010. Polarconsult.
View looking up the existing penstock
from approximately station 8+50. Most
of the penstock is installed on grade or
above grade on timber blocking. Thrust
forces are restrained by a combination of
timber blocking and cables anchored to
rock bolts or trees. The penstock has
significant deferred maintenance, but is
in serviceable condition. At this location,
the thrust restraint cables appear to need
adjustment as the pipe is falling over.
May 11, 2010. Polarconsult.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report B‐6
Photograph B‐11: Existing
Penstock
Photograph B‐12: Existing
Penstock
Photograph B‐13: Existing
Powerhouse
View of existing penstock looking down
from approximately station 11+00. The
penstock is supported by timber
blocking and cables in this area.
May 11, 2010. Polarconsult.
View of existing penstock looking up
from approximately station 8+00. The
penstock is resting directly on grade in
this area.
May 11, 2010. Polarconsult.
View of existing penstock entering
existing powerhouse.
May 11, 2010. Polarconsult.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report B‐7
Photograph B‐14: Existing
Turbine and Generator
Photograph B‐15: Burro
Creek at USS 1560 Property
Line
Burro Creek currently
generates up to 15 kW of
power with a single jet Pelton‐
type wheel driving a 15 kW 3‐
phase alternator. The turbine
governor is a Woodward UG8
mechanical governor.
May 10, 2010. Polarconsult.
View looking downstream Burro
Creek in the vicinity of the
westerly property line of USS
1560. This view is typical of the
creek bed and grade throughout
this reach.
May 11, 2010. Polarconsult.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report B‐8
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report
APPENDIX C – HYDROLOGY DATA
C.1: Available Hydrology Data pages C‐1 to C‐6
C.2: Burro Creek Record Extension pages C‐7 to C‐9
C.3: Burro Creek Hydrology Model page C‐10
C.4: Burro Creek Gauging Station Data pages C‐11 to C‐25
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐1
This Appendix summarizes the hydrology data collected and used for this study.
Approximately 1.8 years of hydrology data have been collected at Burro Creek to date. The
hydrology information described in this Section is used to determine the appropriate installed
capacity of the hydroelectric project, evaluate the expected performance of the project, and
determine the magnitude of flood flows on each creek. Moreover, this hydrology information
can help assess the effect the project may have on the natural environment.
C.1 AVAILABLE HYDROLOGY DATA
Substantially all of the flow in Burro Creek originates as precipitation falling within the Burro
Creek basin. Small glaciers within the basin and alpine groundwater systems make very minor
contributions. The average annual precipitation in the Burro Creek basin is unknown. Total
annual discharge in Burro Creek (calculated as described in this Appendix) amounts to direct
precipitation of approximately 40 inches annually. Actual basin precipitation is higher than this
due to evaporation, sublimation, and transpiration. These observations are consistent with 1‐to‐
2,500,000 scale maps of the region that indicate precipitation in the Burro Creek basin and in the
Skagway vicinity is approximately 80 inches annually 5. Total annual precipitation in Skagway
is only 26 inches. The difference between measured precipitation in Skagway and measured
flows at Burro Creek is attributed to micro‐climate variations in the mountainous terrain.
C.1.1 Site and Gauging Station Description
The Burro Creek gauging station is located at river mile 0.01 at an elevation of approximately 25
feet. It is approximately 375 feet upstream from the log footbridge across Burro Creek, and 275
feet downstream of a prominent waterfall. The gauge is installed in a natural pool in Burro
Creek. The outlet control for this pool is a series of large boulders interlocked with smaller bed
materials and resting on bedrock. This outlet appears relatively stable, but could experience
scour during major flood events.
The gauging station was installed on December 17, 2009. The station has a 0 to 5 psi Acculevel
vented pressure transducer manufactured by Keller America, Inc. The sensor is installed in a
three‐inch diameter HDPE stilling tube mounted to a bedrock wall on the south bank of Burro
Creek. The stilling tube extends into the natural pool, and the sensor is mounted approximately
two feet below annual low water levels to protect it from freezing. This sensor is fitted to a
MONITOR‐1 data logger manufactured by Sutron, Inc. 6 The data logger and power supply are
inside weather tight enclosures mounted on an existing log crib located on rock above the south
bank of Burro Creek. The sensor zero mark is the station zero datum. A staff board is not
installed at the gauging station. The top of the upstream rock bolt on the second bracket down
from the top of the stilling tube is at an elevation of +4.26 feet in the station datum. The logger
is programmed to record stage, battery level, and on‐board temperature at 15‐minute intervals.
Log data is downloaded on a monthly basis by BCH personnel.
5 USGS Water Resources Investigation Report 93‐4179, Plate 2. (Jones and Fahl).
6 The logger was initially deployed with five AA lithium batteries, but these were replaced with a 7 amp‐
hour 12 volt AGM lead‐acid battery and 9 watt amorphous silicon solar panel on March 5, 2010. This
power supply remains in service at the gauging station.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐2
1.75
2.00
2.25
2.50
2.75
3.00
3.25
3.50
3.75
4.00
4.25
4.50
4.75
5.00
5.25
5.50
5.75
6.00
6.25
12/1/09 1/26/10 3/23/10 5/18/10 7/13/10 9/7/10 11/2/10 12/28/1
0
2/22/11 4/19/11 6/14/11 8/9/11 10/4/11Burro Creek Stage (Feet, (Sensor = 0 ft))Photograph B‐3 and B‐8 in Appendix B show the gauging station. It’s location is shown on Map
A‐3. Stage data is presented in Figure C‐1. Daily station records are presented in Section C.4.
Figure C‐1: Burro Creek Stage Data
Source: Polarconsult Alaska, Inc., 2011.
C.1.2 Flow Measurements and Station Calibration
Stream flow in Burro Creek was measured during Polarconsult site visits in December 2009,
May 2010, and September 2011 (Table C‐1).
Table C‐1: Burro Creek Flow Measurements
Date/Time Party Location Flow
(cfs)
Stage
(ft)
Method /
Equipment
Burro Creek Gauge Station Below Falls
12/17/09 15:30 Groves / Wrentmore At log bridge 375’ below gauge 11.0 2.23 Marsh McBirney(1)
12/17/09 16:00 Groves / Wrentmore 200’ reach of stream below gauge 11.3 2.23 Hanna Meter (2)
5/10/10 10:50 Groves / McClendon 200’ reach of stream below gauge 76.0 3.46 Hanna Meter
5/10/10 11:40 Groves / McClendon 200’ reach of stream above gauge 83.0 3.45 Hanna Meter
9/26/11 9:00 Groves / McClendon 300’ reach ‐ gauge to ab. log bridge 47.8 3.25 Hanna Meter
9/26/11 9:30 Groves / McClendon 500’ reach – ab. falls to ab. log bridge 66.2 3.25 Hanna Meter
9/26/11 10:00 McClendon / Groves At gauge pool 59 3.25 Marsh McBirney
9/26/11 10:45 McClendon / Groves At gauge pool 50 3.25 Marsh McBirney
Source: Polarconsult Alaska, Inc., 2011.
(1) Current velocity stream flow method with March McBirney Flowmate 2000 current velocity meter.
(2) Sudden dose salt integration stream flow method with Hanna HI 9828 conductivity meter.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐3
To calibrate the gauging station, Polarconsult performed seven flow measurements to establish
three stage‐discharge points at the stream gauging station (Table C‐1). The resulting
preliminary stage‐discharge rating curve for the station is presented in Figure C‐2. The stage‐
discharge equations and methodology are discussed in this section and the equation parameters
are summarized in Tables C‐2 and C‐3. More measurements are warranted to develop a final
rating curve for the station.
The existing flow measurements and calibrated sections of the stage discharge curve have good
confidence at low and medium flows, which are of primary interest for hydropower
assessment. Because there are few flow measurements at the gauging station, the rating curve
is considered preliminary. Collection of additional flow measurements is recommended to
continue developing the rating curve for the station. Additional measurements at high flows
would improve estimates of infrequent high flow events that have limited hydropower value,
but are important for determining flood flows important for design of the diversion structure.
Additional measurements at moderate and low flows would increase confidence in estimates of
the available hydropower resource.
The stage‐discharge curve for the gauging station was developed using Manning’s equation for
open channel flow (Equation C‐1).
Equation C‐1: Q = 1.49 n –1 A R 2/3 So1/2
Where: Q = flow in cubic feet per second R = hydraulic radius (= A/P)
n = roughness coefficient P = wetted perimeter in feet
A = area, in square feet So = slope in feet per feet
Initial values of So and n were selected based on the physical characteristics of the site, and
adjusted within reason until calculated flows and measured flows were in good agreement.
These values are listed in Table C‐2. The area (A) and wetted perimeter (P) of the creek at the
gauging station are both functions of the stage and the shape of the creek bed. A model of the
creek bed profile was developed for the gauging station, and was used to compute A and P over
the range of stages. Models of the creek bed section profile are listed in Table C‐3 and an
example illustration is shown in Figure C‐2. The computed A and P were then entered into
Equation C‐1 to determine flow from the recorded stage data.
Table C‐2: Manning Equation Parameters for Gauging Station
Gauging Station and Epoch
N
(roughness
coefficient)
So
(Slope in
feet/foot)
A
(Sectional area,
square feet)
P
(Wetted
perimeter, feet)
Burro Creek Gauging Station
(2009 – 2011) 0.04 0.012 Calculated from creek section
parameters listed in Table C‐3.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐4
0
2
4
6
8
10
12
14
0 5 10 15 20 25 30 35 40
Creek Profile at Gauging Station in feet (looking downstream)Stage in Feet (Station Datum)Center
Segment R2
Segment R1Segment L1
Segment L2
1
10
0.1 1 10 100 1000
Discharge (cfs)Stage in Feet(Station Datum)Stage and Discharge Measurements
Rating Curve for Gauging Station
Table C‐3: Creek Sections used to Calculate A and P at Gauging Stations
Gauging Station Segment L2 Segment L1 Center Segment R1 Segment R2
Burro Creek
(2009 – 2011)
Slope = 1.00
Stage = 6.43’
Slope = 0.20
Stage = 4.36’
5.0’ wide
at 1.57’
Slope = 10.0’
Stage = 8.43’
Slope = 0.01’
Stage = 9.43’
Source: Polarconsult Alaska, Inc., 2011.
Figure C‐2: Model Used for Creek Section at Burro Creek
Source: Polarconsult Alaska, Inc., 2011.
Figure C‐3: Burro Creek Stream Gauge Rating Curve
Source: Polarconsult Alaska, Inc., 2011.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐5
58.479.5
11.1
1
10
100
1000
12/13/091/10/102/7/103/7/104/4/105/2/105/30/106/27/107/25/108/22/109/19/1010/17/1011/14/1012/12/101/9/112/6/113/6/114/3/115/1/115/29/116/26/117/24/118/21/119/18/1110/16/11Discharge (cfs)Flow, Calculated from Stage
Flow, Measured
Series3
C.1.3 Calculated Flow and Burro Creek Hydrograph
Each stage reading recorded by the stream gauge is converted to a calculated flow using the
rating curve described in Section C.1.2. The result is a calculated hydrograph for Burro Creek
shown in Figure C‐4. Some of the stage data in Figure C‐1 reflects anomalous data due to
sensor errors or ice affected readings during winter cold spells. These artifacts have been
removed from the calculated flow hydrograph.
Figure C‐4: Burro Creek Hydrograph
Source: Polarconsult Alaska, Inc., 2011.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐6
C.2 BURRO CREEK RECORD EXTENSION
While the 1.8 years of data at Burro Creek provides a good basis for understanding the
hydrology of this resource, it is beneficial to have a longer period of record to improve
understanding of the variability of flow in the resource. This longer period of record can be
synthesized by correlating the 1.8 year record at Burro Creek with concurrent hydrographs of
nearby streams with longer periods of record.
Nearby streams that are suitable candidates for correlation are listed in Table C‐4. Of these,
Taiya River was selected for extending the Burro Creek record because it provided a good
correlation (R2 = 0.86) and has a long period of record (14.8 years).
Table C‐4: Summary of Hydrology Data for Burro Creek and Nearby Resources
Location USGS
Gauge ID
Basin
Size
(sq.mi.)
Site
Elevation
(ft) (1)
Latitude(1) Longitude(1)Begin
Date
End
Date
Number
of Daily
Records(3)
Burro Creek
below Falls ‐ 12.39 25 59° 26’ 02” 135° 22’ 11” 12/18/09 10/12/11 661
Kasidaya
Creek ‐ 21.3 500 59° 24’ 19” 135° 19’ 47” 1/1/99 3/29/02 1,183
Taiya River 15056210 179 20 59° 30’ 49” 135° 21’ 7” 1/1/71 11/18/77 2,514
10/1/03 10/12/11 2,925
Kakuhan
Creek 15056030 1.53 25 59° 17’ 32” 135° 22’ 01” 5/14/97 10/12/11 5,115
Source: Polarconsult Alaska, Inc., 2011.
(1) Coordinates for U.S. Geological Survey gauges are in North American Datum of 1927 (NAD 27). All
other coordinates are in NAD 83.
(2) Count of available daily records. Gauges may have been in service for a longer period.
(3) The record count for current gauging stations reflects data through the most recent download on
October 12, 2011.
The Burro Creek and Taiya River basins are geographically close to each other, and are expected
to experience similar weather systems and events. The basins are similar in many respects, but
do have several significant differences:
1. Size. The Burro Creek basin area is approximately 7% of the Taiya River basin area. All
else equal, the smaller Burro Creek basin can be expected to experience more volatile
discharge, such as more severe droughts and floods.
2. Glaciation. Approximately 3% of the Burro Creek basin is glaciated, whereas
approximately 22% of the Taiya River basin is glaciated. Seasonal melt of the glaciers in
the Taiya River basin will result in Taiya River having relatively greater discharge that
Burro Creek during the summer months.
3. Basin Orientation. The Burro Creek basin is oriented facing east‐southeast, whereas the
Taiya River basin is oriented facing south‐southeast. The Taiya River basin is somewhat
better oriented to capture precipitation from storms from the Gulf of Alaska than the
Burro Creek basin.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐7
4. Altitude. The average elevation of the Burro Creek basin is approximately 3,100’. This
is significantly lower than the Taiya River basin, which has an average elevation of
approximately 3,500’. Taiya River’s higher basin is consistent with its greater glaciation,
as the higher basin can be expected to receive more precipitation and colder
temperatures.
The average daily flows at Burro Creek and Taiya River over their 1.8 year common period of
record have a correlation of 0.61. Based upon analysis of the data, a piece‐wise linear model
was developed to calculate expected Burro Creek flow from the Taiya River flow data. This
more complex model accounts for some of the subtle differences between the Taiya River and
Burro Creek basins by applying different relationships for different seasons and flow regimes.
Table C‐5 summarizes the model parameters. The expected Burro Creek flows calculated using
this model have a correlation with the Burro Creek gauging station daily flows of 0.86. These
models are shown graphically in Figure C‐5.
Table C‐5: Burro Creek Flow Model Parameters
Model For
October 1 – June 30
Model For
August 1 – August 31
Taiya River
Flow
Equation For Burro Creek
Flow
Taiya River
Flow
Equation For Burro Creek
Flow
0 to 145 cfs QBurro = 0.110 QTaiya – 0.3 0 to 85 cfs QBurro = 0.110 QTaiya – 0.3
145 to 920 cfs QBurro = 0.110 QTaiya – 1.0
85+ cfs QBurro = 0.024 QTaiya + 7.0
920+ cfs QBurro = 0.030 QTaiya + 73
Source: Polarconsult Alaska, Inc., 2011.
Model flows for the months of July and September are calculated as a linear ramping function between
the two models above, with the October‐June model weight decreasing from 100% to 0% during July, and
vice versa during September.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐8
1
10
100
1,000
10 100 1,000 10,000Taiya River Flow (cfs)Burro Creek Flow (cfs)Standard Linear Correlation Model
Daily Flows, October ‐ June
Flow Model, October ‐ June
Daily Flows, July ‐ September
Flow Model, August*
* Flows for the months of July and September are calcuated as a weighted average of the two models shown. The June model receives 100% weighting on July 1st,
decreasing to 0% by July 31st. The opposite transition occurs for the month of September.
(R2 = 0.61)
(R2 = 0.86)
Figure C‐5: Burro Creek and Taiya River Flow Data and Models
Source: Polarconsult Alaska, Inc., 2011.
The extended Burro Creek record using the Taiya River record set is presented graphically in
Figure C‐6. Flow statistics calculated using the 14.8 years of Taiya River record are presented
graphically in Figure C‐7.
Burro Creek Holdings, LLC Burro Creek Hydroelectric Study Polarconsult Alaska, Inc. November 2011 – Final Report C‐9 Figure C‐6: Extended Burro Creek Record Using Taiya River Flow Model 0501001502002503003501/1/717/1/711/1/727/1/721/1/737/1/731/1/747/1/741/1/757/1/751/1/767/1/761/1/777/1/77Expected Burro Creek Flow, cfs (record extension) 05010015020025030035010/1/034/1/0410/1/044/1/0510/1/054/1/0610/1/064/1/0710/1/074/1/0810/1/084/1/0910/1/094/1/1010/1/104/1/1110/1/11Burro Creek Flow RecordExtended Burro Creek Flow Record
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐10
0
50
100
150
200
250
300
350
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecDaily Flow Statistics for Burro Creek Extended Record, cfsMaximum Daily Flow
Mean Daily Flow
Median Daily Flow
Minimum Daily Flow
Statistics are based on the extended record for Burro Creek compiled using Taiya River record from USGS gauge #15056210. Correlation between calculated flow
at Burro Creek gauge and Taiya River record extension is R^2 = 0.81 for the period 12/19/2009 ‐ 8/17/2011. Daily flow statistics shown in this figure are based on
5,383 daily flow records at Taiya River from 1/1/1971 ‐ 11/18 1977 and 10/1/2003 ‐ 8/9/2011.
C.3 BURRO CREEK HYDROLOGY MODEL
The extended hydrology record for Burro Creek forms the basis of a hydrology model used to
estimate the energy generation potential of various hydroelectric project configurations
considered in this study.
Flow statistics were calculated on a daily basis using the 14.7 year extended record for Burro
Creek. The resulting flow statistics for the Burro Creek gauging station are presented in Figure
C‐7.
Figure C‐7: Daily Flow Statistics for Extended Burro Creek Flow Record
Source: Polarconsult Alaska, Inc., 2011.
Flows at the various diversion sites were estimated by prorating the model flow at the gauging
station by relative basin areas (Table C‐6, Figure A‐2). Project flow statistics for a given project
configuration were then estimated by clipping the complete extended flow record at the design
flow, and then computing the median daily flow from the resulting clipped data set. Figure C‐8
provides an example of the resulting estimated project flow for a 70 cfs project with a diversion
at 800’ and a powerhouse at the existing powerhouse site.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum Voltage
12/18/09 88 2.22 2.24 2.28 10.9 11.4 12.7 31.4 32.3 35.7 15.95 (2)
12/19/09 96 2.20 2.21 2.26 10.1 10.6 12.0 24.4 27.9 32.0 15.77
12/20/09 96 2.19 2.26 2.33 10.0 12.1 14.3 17.6 20.2 24.8 15.57
12/21/09 96 2.28 2.35 2.46 12.7 15.1 19.1 14.4 16.4 19.1 15.47
12/22/09 96 2.44 2.55 2.68 18.3 22.8 29.0 14.1 16.1 19.9 15.44
12/23/09 96 2.30 2.50 2.72 13.2 21.3 30.8 20.2 22.2 23.6 15.59
12/24/09 96 2.22 2.26 2.32 10.7 12.0 13.9 23.7 25.5 28.3 15.66
12/25/09 96 2.17 2.20 2.22 9.3 10.1 10.8 28.5 30.1 31.2 15.75
12/26/09 96 2.15 2.21 2.26 8.9 10.5 11.9 31.1 31.2 31.5 15.76
12/27/09 96 2.22 2.24 2.26 10.7 11.3 12.1 31.2 31.4 31.8 15.75
12/28/09 96 2.26 2.28 2.30 12.1 12.8 13.2 31.6 31.7 31.9 15.75
12/29/09 96 2.23 2.26 2.28 11.1 11.9 12.8 27.3 29.6 32.0 15.69
12/30/09 96 2.20 2.22 2.23 10.2 10.7 11.2 21.7 26.2 27.7 15.58
12/31/09 96 2.15 2.21 2.26 8.8 10.6 12.1 14.1 17.1 21.7 15.31
1/1/10 96 2.26 2.53 3.07 12.1 23.3 51.6 11.4 12.7 14.5 15.17
1/2/10 96 3.07 3.22 3.37 51.5 62.3 74.1 10.8 12.3 14.1 15.14
1/3/10 96 3.20 3.35 3.45 60.5 72.1 80.3 11.2 13.9 17.4 15.19
1/4/10 96 2.88 3.02 3.22 39.4 48.7 62.2 14.3 16.4 18.3 15.26
1/5/10 96 2.59 2.76 2.87 24.7 32.9 39.2 16.2 17.7 20.0 15.28
1/6/10 96 2.18 2.46 2.76 9.6 20.0 32.7 17.7 19.8 24.7 15.35
1/7/10 96 2.11 2.15 2.18 7.8 8.7 9.6 24.9 26.6 29.7 15.56
1/8/10 96 2.12 2.14 2.16 7.9 8.4 9.0 29.8 30.9 31.5 15.67
1/9/10 96 2.14 2.31 2.46 8.5 13.9 18.9 30.8 31.7 32.9 15.67
1/10/10 96 2.22 2.29 2.40 10.7 13.0 16.7 28.6 31.0 32.2 15.66
1/11/10 96 2.17 2.21 2.24 9.5 10.5 11.5 11.5 18.4 28.5 15.32
1/12/10 96 2.20 2.21 2.23 10.3 10.6 11.1 10.0 10.3 10.0 15.05
1/13/10 96 2.17 2.18 2.20 9.4 9.8 10.3 11.5 14.8 19.8 15.17
1/14/10 96 2.15 2.17 2.18 8.7 9.3 9.6 20.1 23.1 27.2 15.41
1/15/10 96 2.14 2.16 2.18 8.5 9.0 9.5 25.1 26.3 28.1 15.50
1/16/10 96 2.13 2.18 2.28 8.4 9.8 12.6 28.2 32.5 34.7 15.66
1/17/10 96 2.23 2.47 2.74 11.2 19.9 31.8 31.2 32.5 34.2 15.65
1/18/10 96 2.32 2.41 2.56 13.9 17.4 23.2 31.1 32.0 32.7 15.64
1/19/10 96 2.26 2.29 2.33 11.9 12.9 14.2 29.4 31.2 32.8 15.61
1/20/10 96 2.23 2.24 2.26 11.0 11.4 12.1 29.6 30.3 31.8 15.57
1/21/10 96 2.20 2.21 2.23 10.2 10.6 11.0 29.2 30.3 32.1 15.55
1/22/10 96 2.18 2.19 2.20 9.7 10.0 10.3 29.4 31.4 34.2 15.58
1/23/10 96 2.17 2.18 2.19 9.3 9.6 9.9 31.1 32.0 34.7 15.58
1/24/10 96 2.16 2.17 2.18 9.1 9.3 9.5 27.0 29.1 33.7 15.48
1/25/10 96 2.15 2.16 2.17 8.8 9.0 9.2 24.1 25.7 27.9 15.36
1/26/10 96 2.14 2.15 2.16 8.5 8.8 9.0 22.4 23.6 25.6 15.29
1/27/10 96 2.14 2.14 2.15 8.4 8.6 8.7 24.3 25.5 26.3 15.35
1/28/10 96 2.13 2.14 2.14 8.3 8.4 8.5 26.7 29.2 32.3 15.44
1/29/10 96 2.12 2.13 2.14 8.1 8.3 8.4 26.6 30.1 34.4 15.45
1/30/10 96 2.12 2.12 2.15 8.0 8.1 8.7 31.5 32.6 34.5 15.52
1/31/10 96 2.11 2.12 2.13 7.9 8.0 8.2 31.7 32.3 33.8 15.50
2/1/10 96 2.11 2.11 2.13 7.8 7.9 8.3 31.4 32.1 33.7 15.48
2/2/10 96 2.10 2.11 2.12 7.6 7.8 7.9 30.5 31.7 33.0 15.45
2/3/10 96 2.10 2.10 2.11 7.5 7.6 7.8 29.7 31.0 33.6 15.41
2/4/10 96 2.09 2.10 2.10 7.4 7.5 7.6 27.1 28.6 32.0 15.32
2/5/10 96 2.09 2.09 2.10 7.2 7.3 7.5 28.7 29.4 30.5 15.30
2/6/10 96 2.09 2.09 2.10 7.2 7.3 7.6 28.8 30.1 31.8 15.29
2/7/10 96 2.10 2.19 2.35 7.6 10.1 15.0 31.5 33.0 38.2 15.35
2/8/10 96 2.31 2.35 2.39 13.5 15.2 16.3 31.4 33.3 36.9 15.33
Date Notes
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
2/9/10 96 2.24 2.27 2.31 11.3 12.3 13.6 31.3 32.9 35.1 15.29
2/10/10 96 2.20 2.22 2.24 10.3 10.8 11.3 29.9 30.9 33.8 15.21
2/11/10 96 2.18 2.19 2.20 9.5 9.9 10.3 29.5 30.5 32.6 15.14
2/12/10 96 2.16 2.17 2.18 9.1 9.4 9.7 30.7 32.0 33.7 15.16
2/13/10 96 2.15 2.15 2.16 8.7 8.9 9.2 29.5 31.2 33.5 15.09
2/14/10 96 2.14 2.15 2.15 8.5 8.7 8.8 31.9 33.6 36.1 15.12
2/15/10 96 2.14 2.17 2.19 8.5 9.4 10.0 31.9 34.5 37.5 15.09
2/16/10 96 2.16 2.17 2.18 9.2 9.3 9.6 31.1 33.6 37.2 15.00
2/17/10 96 2.16 2.20 2.23 9.2 10.3 11.1 33.2 37.5 40.1 15.10
2/18/10 96 2.21 2.23 2.24 10.6 11.0 11.4 29.2 32.7 36.8 14.87
2/19/10 96 2.20 2.21 2.22 10.2 10.5 10.9 28.7 30.2 32.5 14.67
2/20/10 96 2.20 2.22 2.25 10.1 10.7 11.7 27.9 30.0 33.6 14.53
2/21/10 96 2.25 2.26 2.27 11.6 11.9 12.3 27.0 28.9 31.3 14.30
2/22/10 96 2.25 2.26 2.27 11.7 12.0 12.3 25.4 28.0 31.6 14.11
2/23/10 96 2.24 2.25 2.26 11.3 11.6 11.9 25.5 28.1 31.8 13.96
2/24/10 96 2.22 2.23 2.24 10.8 11.1 11.4 30.5 31.7 33.8 13.94
2/25/10 96 2.20 2.21 2.23 10.3 10.6 11.0 31.1 32.4 35.6 13.75
2/26/10 96 2.18 2.21 2.22 9.5 10.5 10.8 32.6 35.2 37.7 13.53
2/27/10 96 2.20 2.21 2.22 10.3 10.5 10.7 27.6 30.7 37.4 13.07
2/28/10 96 2.21 2.21 2.23 10.4 10.6 11.2 31.1 31.8 34.7 12.84
3/1/10 96 2.23 2.26 2.33 11.2 12.2 14.3 31.2 31.6 33.6 12.50
3/2/10 4 2.34 2.34 2.34 14.5 14.6 14.8 33.3 33.4 33.5 12.31 (3)
3/5/10 89 2.30 2.33 2.36 13.4 14.3 15.4 32.4 34.7 42.5 13.00
3/6/10 96 2.29 2.30 2.31 13.1 13.4 13.6 31.3 33.2 34.5 12.98
3/7/10 96 2.30 2.33 2.38 13.3 14.4 16.2 30.0 33.1 35.9 13.19
3/8/10 96 2.26 2.28 2.30 12.1 12.7 13.4 27.5 30.3 35.1 13.20
3/9/10 96 2.26 2.27 2.28 11.9 12.2 12.5 29.1 31.5 34.0 13.13
3/10/10 96 2.23 2.25 2.28 11.1 11.7 12.6 29.1 31.6 36.1 13.21
3/11/10 96 2.21 2.22 2.23 10.6 10.8 11.2 30.1 32.1 37.0 13.29
3/12/10 96 2.19 2.20 2.22 9.9 10.4 10.7 30.3 33.0 38.0 13.28
3/13/10 96 2.19 2.19 2.20 9.8 10.0 10.2 29.5 30.5 32.9 13.18
3/14/10 96 2.18 2.19 2.19 9.7 9.8 10.0 31.0 31.4 32.9 13.20
3/15/10 96 2.19 2.21 2.24 9.8 10.5 11.5 31.2 31.8 34.4 13.28
3/16/10 96 2.19 2.21 2.22 10.0 10.4 10.7 30.2 32.5 36.1 13.23
3/17/10 96 2.19 2.20 2.20 9.9 10.1 10.2 33.2 34.4 39.0 13.32
3/18/10 96 2.18 2.19 2.20 9.7 9.9 10.1 32.1 35.1 41.0 13.33
3/19/10 96 2.18 2.19 2.19 9.6 9.8 10.0 29.8 33.3 40.2 13.36
3/20/10 96 2.18 2.18 2.19 9.5 9.7 9.9 31.7 33.5 37.5 13.32
3/21/10 96 2.17 2.17 2.18 9.3 9.5 9.6 27.4 30.8 37.6 13.26
3/22/10 96 2.16 2.16 2.17 9.0 9.2 9.4 26.1 28.6 32.3 13.33
3/23/10 96 2.15 2.16 2.16 8.8 9.0 9.1 30.2 32.2 36.9 13.33
3/24/10 96 2.15 2.16 2.16 8.8 9.0 9.2 30.9 31.9 34.4 13.34
3/25/10 96 2.15 2.15 2.16 8.7 8.8 9.0 31.4 32.6 36.2 13.35
3/26/10 96 2.14 2.14 2.15 8.5 8.7 8.9 27.8 31.3 37.2 13.38
3/27/10 96 2.14 2.15 2.16 8.5 8.8 9.1 31.1 34.8 41.2 13.39
3/28/10 96 2.15 2.19 2.27 8.9 9.9 12.3 32.6 35.6 42.3 13.34
3/29/10 96 2.27 2.29 2.30 12.2 12.9 13.4 32.5 36.6 43.1 13.40
3/30/10 96 2.24 2.26 2.27 11.5 11.9 12.4 28.0 34.3 45.5 13.41
3/31/10 96 2.24 2.25 2.25 11.4 11.6 11.7 33.3 36.4 41.6 13.41
4/1/10 96 2.24 2.25 2.26 11.5 11.9 12.1 32.7 35.6 43.5 13.42
4/2/10 96 2.25 2.26 2.27 11.7 12.0 12.2 33.1 36.4 41.8 13.40
4/3/10 96 2.25 2.26 2.27 11.8 12.1 12.3 32.6 37.0 46.0 13.40
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
4/4/10 96 2.24 2.26 2.27 11.5 12.0 12.3 30.9 37.3 47.1 13.42
4/5/10 96 2.23 2.25 2.26 11.2 11.6 11.9 27.9 34.7 44.2 13.42
4/6/10 96 2.23 2.24 2.25 11.2 11.5 11.7 31.6 36.1 44.5 13.40
4/7/10 96 2.22 2.24 2.25 10.9 11.3 11.7 28.2 33.6 41.4 13.39
4/8/10 96 2.21 2.22 2.23 10.4 10.7 11.1 30.0 33.4 38.7 13.43
4/9/10 96 2.19 2.20 2.21 9.9 10.2 10.5 27.3 32.8 42.0 13.42
4/10/10 96 2.18 2.18 2.19 9.5 9.8 10.0 27.4 32.5 41.8 13.34
4/11/10 96 2.17 2.18 2.18 9.4 9.6 9.7 27.2 31.9 40.6 13.30
4/12/10 96 2.18 2.19 2.20 9.6 9.8 10.1 26.0 32.1 44.8 13.31
4/13/10 96 2.19 2.21 2.23 10.0 10.4 11.0 34.5 38.8 45.2 13.43
4/14/10 96 2.22 2.23 2.24 10.8 11.1 11.4 40.3 42.9 47.8 13.44
4/15/10 96 2.23 2.28 2.32 11.2 12.6 13.9 30.0 38.4 52.8 13.40
4/16/10 96 2.31 2.40 2.47 13.6 16.8 19.6 30.6 37.9 55.3 13.42
4/17/10 96 2.46 2.65 2.77 19.0 27.8 33.4 36.4 42.2 56.5 13.42
4/18/10 96 2.72 2.80 2.86 30.7 35.1 38.5 35.2 40.3 48.2 13.45
4/19/10 96 2.81 2.89 2.97 35.4 40.0 44.8 36.4 41.2 49.2 13.45
4/20/10 96 2.97 3.22 3.34 45.3 62.1 71.4 36.3 39.7 46.8 13.42
4/21/10 96 3.29 3.47 3.60 67.6 82.7 94.7 34.3 38.7 44.8 13.44
4/22/10 96 3.07 3.17 3.31 51.2 58.7 68.7 35.9 41.0 58.7 13.44
4/23/10 96 3.02 3.08 3.13 48.4 52.3 55.8 34.7 40.7 60.2 13.45
4/24/10 96 2.90 2.97 3.02 41.0 45.1 48.1 30.8 40.1 65.9 13.37
4/25/10 96 2.90 2.98 3.04 40.7 45.7 49.6 34.1 42.6 67.1 13.42
4/26/10 96 2.95 3.05 3.12 43.7 50.5 54.7 37.4 45.3 56.5 13.46
4/27/10 96 3.11 3.38 3.49 53.9 75.2 84.0 36.5 45.2 56.0 13.44
4/28/10 96 3.43 3.72 3.85 78.8 106.1 120.3 38.4 46.9 72.3 13.46
4/29/10 96 3.59 3.70 3.79 93.7 104.4 113.7 37.6 43.2 55.0 13.43
4/30/10 96 3.51 3.64 3.74 85.7 98.1 108.5 37.4 41.8 51.1 13.46
5/1/10 96 3.33 3.44 3.52 70.8 79.8 86.9 36.8 42.5 54.6 13.46
5/2/10 96 3.24 3.30 3.34 63.4 68.7 71.1 38.7 44.9 58.3 13.47
5/3/10 96 3.14 3.21 3.25 56.6 61.8 64.2 33.8 43.8 72.0 13.45
5/4/10 96 3.11 3.14 3.17 54.0 56.4 58.6 39.0 45.9 59.9 13.47
5/5/10 96 3.13 3.29 3.39 55.5 67.5 75.4 36.5 45.1 64.9 13.41
5/6/10 96 3.28 3.42 3.53 66.4 78.7 87.5 36.9 45.1 76.6 13.46
5/7/10 96 3.36 3.45 3.53 73.1 81.1 87.6 37.7 47.8 79.0 13.45
5/8/10 96 3.41 3.52 3.62 77.1 86.9 96.4 36.1 45.4 77.5 13.42
5/9/10 96 3.41 3.47 3.53 77.0 82.6 87.9 32.9 44.5 77.0 13.35
5/10/10 96 3.40 3.49 3.57 76.8 84.7 91.7 33.2 45.3 80.1 13.36
5/11/10 96 3.44 3.52 3.59 80.1 86.7 93.3 42.0 50.3 82.2 13.46
5/12/10 96 3.41 3.44 3.47 77.6 80.1 82.0 40.3 46.4 57.1 13.44
5/13/10 96 3.42 3.55 3.66 77.7 89.5 99.9 40.3 46.2 55.2 13.48
5/14/10 96 3.31 3.40 3.48 68.9 76.9 83.4 37.2 46.8 65.8 13.47
5/15/10 96 3.30 3.40 3.47 68.5 76.8 82.7 39.4 48.8 75.8 13.46
5/16/10 96 3.42 3.62 3.77 77.9 96.7 111.3 37.4 47.2 76.9 13.47
5/17/10 96 3.48 3.57 3.68 83.0 91.9 102.1 33.6 46.6 82.1 13.39
5/18/10 96 3.46 3.60 3.72 81.4 94.6 105.6 37.5 49.9 83.7 13.46
5/19/10 96 3.57 4.10 4.68 91.1 151.8 231.1 40.5 48.3 74.3 13.44
5/20/10 96 4.07 4.52 4.81 144.9 207.5 253.3 36.5 46.0 74.0 13.36
5/21/10 96 4.07 4.40 4.58 144.9 189.3 214.8 41.8 51.2 79.8 13.43
5/22/10 96 4.15 4.39 4.58 154.5 188.1 214.9 38.2 45.4 67.3 13.35
5/23/10 96 4.20 4.49 4.71 161.2 202.1 235.5 38.5 49.7 85.7 13.39
5/24/10 96 4.26 4.57 4.77 169.9 215.3 246.7 40.9 51.4 84.7 13.42
5/25/10 96 4.40 4.61 4.82 189.1 221.5 254.8 38.7 48.3 77.1 13.37
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
5/26/10 96 4.43 4.71 4.97 193.6 236.4 281.3 40.9 49.5 74.8 13.46
5/27/10 96 4.51 4.74 4.92 204.9 241.9 272.4 41.4 52.0 77.6 13.34
5/28/10 96 4.66 4.93 5.29 228.6 274.9 342.2 40.8 50.2 75.3 13.37
5/29/10 96 4.59 4.92 5.23 217.4 273.4 329.3 40.1 51.0 77.4 13.44
5/30/10 96 4.53 4.78 5.05 208.1 248.3 295.8 41.5 51.9 82.8 13.38
5/31/10 96 4.41 4.71 5.01 190.4 237.1 287.7 39.8 50.1 76.7 13.37
6/1/10 96 4.41 4.59 4.78 190.7 217.9 248.0 42.8 52.0 82.9 13.44
6/2/10 96 4.28 4.45 4.61 171.9 196.5 219.9 40.8 49.7 74.2 13.40
6/3/10 96 4.46 4.79 5.04 197.1 249.9 294.1 41.4 48.3 64.9 13.40
6/4/10 96 4.10 4.42 4.63 149.4 192.4 222.5 42.2 50.5 74.7 13.45
6/5/10 96 3.97 4.12 4.29 133.1 152.1 173.4 40.8 49.7 69.8 13.43
6/6/10 96 3.97 4.15 4.29 133.6 155.4 174.1 42.8 53.8 82.2 13.47
6/7/10 96 4.01 4.20 4.43 138.3 162.0 193.4 39.7 52.0 86.7 13.36
6/8/10 96 4.01 4.20 4.40 137.9 161.5 188.1 41.7 54.1 90.6 13.43
6/9/10 96 4.02 4.18 4.36 139.2 159.5 182.9 43.4 53.0 81.9 13.47
6/10/10 96 4.08 4.29 4.50 146.6 174.6 202.7 42.4 54.0 84.4 13.43
6/11/10 96 4.09 4.26 4.43 147.2 170.0 192.4 44.4 52.4 76.3 13.46
6/12/10 96 4.10 4.22 4.32 149.0 164.5 177.5 40.8 43.7 49.7 13.43
6/13/10 96 3.88 4.08 4.24 122.6 146.7 167.0 42.1 47.8 58.8 13.44
6/14/10 96 3.70 3.83 3.93 104.1 117.8 128.4 45.7 52.1 78.2 13.46
6/15/10 96 3.69 3.73 3.77 102.6 107.4 111.7 46.1 50.6 57.4 13.43
6/16/10 96 3.71 3.78 3.83 105.4 112.4 117.1 45.1 50.3 58.8 13.41
6/17/10 96 3.73 3.81 3.87 106.8 115.7 122.1 45.1 51.2 64.6 13.45
6/18/10 96 3.75 3.86 3.93 108.8 120.4 128.4 46.0 51.5 58.8 13.44
6/19/10 96 3.79 3.87 3.93 113.0 122.2 129.0 45.6 54.3 84.7 13.46
6/20/10 96 3.81 3.90 3.98 115.7 124.9 134.5 44.7 55.4 87.8 13.46
6/21/10 96 3.84 4.10 4.25 119.2 149.7 168.6 43.0 54.2 82.6 13.40
6/22/10 96 4.05 4.22 4.35 142.4 164.0 181.2 46.1 52.4 73.9 13.45
6/23/10 96 4.00 4.20 4.79 136.6 162.8 249.2 44.5 47.5 52.5 13.42
6/24/10 96 4.61 4.94 5.24 220.0 276.9 331.3 43.4 45.5 50.6 13.38
6/25/10 96 4.39 4.51 4.66 187.1 204.9 227.9 45.8 49.4 55.3 13.43
6/26/10 96 4.05 4.26 4.45 142.9 170.5 196.2 44.1 50.5 72.6 13.45
6/27/10 96 3.89 3.97 4.04 124.3 133.1 141.6 44.7 49.7 55.8 13.43
6/28/10 96 3.75 3.93 4.07 109.1 128.8 145.6 41.7 53.8 86.9 13.42
6/29/10 96 3.59 3.70 3.78 93.8 104.2 112.3 41.4 52.5 83.0 13.42
6/30/10 96 3.60 3.92 4.68 94.7 131.3 231.1 44.2 52.1 75.1 13.37
7/1/10 96 4.11 4.36 4.61 149.5 183.2 220.3 43.1 45.9 54.9 13.41
7/2/10 96 3.84 3.96 4.14 119.0 132.6 154.3 45.4 49.2 56.2 13.41
7/3/10 96 3.77 3.83 3.90 110.9 117.9 125.5 46.2 49.8 56.1 13.44
7/4/10 96 3.78 4.15 4.56 112.4 157.2 212.8 44.9 47.0 52.2 13.35
7/5/10 96 4.08 4.28 4.48 146.2 173.1 200.4 46.1 50.0 59.3 13.46
7/6/10 96 3.92 4.16 4.53 127.0 157.5 207.9 45.7 48.4 52.5 13.37
7/7/10 96 4.36 4.79 5.23 183.3 251.4 330.9 44.9 47.0 53.7 13.40
7/8/10 96 4.09 4.38 4.67 147.6 186.6 229.2 43.9 52.5 80.1 13.42
7/9/10 96 3.96 4.14 4.29 132.2 153.8 173.7 44.9 56.1 89.7 13.38
7/10/10 96 3.98 4.20 4.46 134.1 162.4 197.5 49.0 56.1 79.3 13.42
7/11/10 96 4.10 4.36 4.56 148.8 184.0 212.0 49.9 53.3 58.2 13.45
7/12/10 96 3.72 3.95 4.16 106.3 131.1 156.2 45.5 51.6 69.8 13.43
7/13/10 96 3.67 3.71 3.78 100.8 105.5 111.9 49.2 53.5 64.9 13.41
7/14/10 96 3.66 3.71 3.81 99.9 105.3 115.0 48.4 52.0 57.4 13.38
7/15/10 96 3.61 3.73 3.82 95.2 106.9 117.0 46.7 51.8 63.5 13.46
7/16/10 96 3.58 3.62 3.66 92.5 96.3 100.4 48.4 51.7 56.8 13.41
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
7/17/10 96 3.56 3.62 3.66 91.0 96.2 99.7 47.5 52.3 59.4 13.41
7/18/10 96 3.56 3.63 3.71 90.3 97.1 105.0 48.6 56.3 84.6 13.40
7/19/10 96 3.54 3.62 3.72 88.8 96.8 106.2 50.0 60.1 92.9 13.42
7/20/10 96 3.52 3.56 3.61 86.6 91.0 95.6 48.9 58.5 87.0 13.42
7/21/10 96 3.51 3.58 3.64 86.0 92.2 98.4 49.3 53.9 61.0 13.40
7/22/10 96 3.59 3.66 3.73 93.1 100.2 106.7 50.3 55.1 63.2 13.43
7/23/10 96 3.63 3.68 3.76 97.1 101.9 110.3 47.3 55.7 92.9 13.42
7/24/10 96 3.73 4.06 4.44 107.2 144.7 194.0 46.8 48.5 53.5 13.37
7/25/10 96 3.58 3.70 3.84 92.8 104.0 119.1 48.9 53.2 58.2 13.42
7/26/10 96 3.47 3.55 3.61 82.0 89.9 94.8 47.5 52.6 60.0 13.42
7/27/10 96 3.45 3.52 3.62 80.5 87.3 96.4 45.1 57.1 90.9 13.38
7/28/10 96 3.45 3.62 3.71 81.0 96.0 105.3 48.7 59.7 91.4 13.40
7/29/10 96 3.49 3.56 3.60 84.3 90.5 94.0 51.4 55.5 61.1 13.42
7/30/10 96 3.45 3.52 3.58 81.1 86.9 92.3 50.2 59.7 87.0 13.41
7/31/10 96 3.41 3.45 3.48 77.7 80.4 83.5 49.4 57.0 83.1 13.42
8/1/10 96 3.44 3.60 3.76 79.4 95.1 110.6 49.0 51.5 60.3 13.33
8/2/10 96 3.50 3.57 3.62 84.9 91.1 96.3 51.0 55.8 64.4 13.42
8/3/10 96 3.49 3.57 3.67 84.6 91.9 100.8 49.1 57.8 84.3 13.31
8/4/10 96 3.52 3.64 3.75 87.2 98.2 109.0 49.2 58.1 85.8 13.34
8/5/10 96 3.53 3.63 3.72 88.0 97.0 106.1 52.1 57.8 86.0 13.35
8/6/10 96 3.56 3.66 3.76 90.3 100.2 110.0 52.4 54.6 59.1 13.35
8/7/10 96 3.52 3.62 3.73 86.6 96.8 106.9 51.4 54.2 62.0 13.35
8/8/10 96 3.44 3.48 3.52 80.1 83.0 86.8 50.4 52.9 56.7 13.38
8/9/10 96 3.42 3.50 3.81 78.1 85.2 115.4 50.7 54.0 60.7 13.41
8/10/10 96 3.50 3.66 4.20 85.1 101.1 161.7 52.5 55.7 64.3 13.38
8/11/10 96 3.71 4.00 4.34 105.1 138.5 180.4 51.7 54.8 62.6 13.37
8/12/10 96 3.43 3.57 3.73 78.7 92.0 107.0 49.9 57.3 81.2 13.40
8/13/10 96 3.37 3.42 3.47 73.6 78.3 82.0 49.1 58.1 87.0 13.35
8/14/10 96 3.30 3.37 3.44 68.2 74.3 80.0 48.2 57.1 84.9 13.26
8/15/10 96 3.31 3.41 3.47 68.8 77.3 82.2 51.5 58.5 80.4 13.31
8/16/10 96 3.36 3.45 3.53 73.2 80.4 87.5 51.3 58.9 83.2 13.36
8/17/10 96 3.36 3.41 3.48 73.2 77.3 83.0 55.5 62.1 84.2 13.38
8/18/10 96 3.33 3.66 4.03 70.6 102.0 140.3 52.2 55.2 63.4 13.32
8/19/10 96 3.48 3.66 3.99 83.5 100.2 135.4 49.7 53.6 64.6 13.38
8/20/10 96 3.32 3.38 3.46 69.8 74.9 81.9 50.0 53.2 61.6 13.38
8/21/10 96 3.18 3.29 3.40 59.2 68.0 76.2 46.3 50.6 56.4 13.40
8/22/10 96 3.06 3.13 3.19 50.6 56.0 60.0 48.9 53.4 66.7 13.36
8/23/10 96 3.05 3.10 3.17 50.3 53.4 58.8 49.0 52.7 62.2 13.40
8/24/10 96 3.11 3.20 3.28 54.3 60.6 66.7 46.5 50.0 55.4 13.39
8/25/10 96 3.02 3.09 3.14 48.5 52.9 56.5 48.5 51.8 63.8 13.39
8/26/10 96 3.03 3.13 3.25 48.6 55.4 64.1 49.0 51.5 56.6 13.39
8/27/10 96 3.01 3.07 3.12 47.8 51.3 54.6 47.3 51.9 65.1 13.37
8/28/10 96 2.96 3.00 3.03 44.4 46.9 49.1 49.0 53.1 65.0 13.37
8/29/10 96 2.95 2.99 3.09 43.8 46.4 52.5 47.8 52.1 60.3 13.37
8/30/10 96 2.89 2.95 3.00 40.1 43.9 47.1 46.1 50.3 60.5 13.36
8/31/10 96 2.84 2.89 2.93 37.3 40.4 42.8 46.1 49.9 58.7 13.33
9/1/10 96 2.84 2.88 2.93 37.4 39.8 42.7 49.1 53.3 62.5 13.36
9/2/10 96 2.85 2.94 3.13 38.0 43.6 55.5 47.9 51.6 60.8 13.35
9/3/10 96 2.92 3.01 3.13 42.1 47.6 55.4 47.0 50.6 60.1 13.32
9/4/10 96 2.85 2.91 2.95 37.6 41.1 43.6 46.9 50.2 56.2 13.55
9/5/10 96 2.83 2.86 3.34 36.5 38.6 71.7 48.4 52.0 58.4 13.50
9/6/10 96 3.24 3.48 3.81 63.9 84.4 115.0 45.0 47.4 52.4 13.47
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
9/7/10 96 3.09 3.18 3.24 52.5 59.2 63.5 46.5 51.4 58.7 13.46
9/8/10 96 3.00 3.08 3.13 47.2 52.2 55.8 46.4 50.9 57.8 13.43
9/9/10 96 3.00 3.13 3.46 46.8 56.2 81.3 48.8 49.6 51.0 13.33
9/10/10 96 3.09 3.24 3.42 52.5 64.3 78.2 44.2 48.4 53.0 13.42
9/11/10 96 3.06 3.12 3.20 50.6 55.2 60.9 46.8 49.2 53.7 13.39
9/12/10 96 3.03 3.09 3.14 48.9 52.8 56.6 47.3 50.5 55.1 13.39
9/13/10 96 2.91 2.99 3.04 41.3 46.1 49.4 43.8 48.9 57.5 13.36
9/14/10 96 2.81 2.88 2.93 35.7 39.6 42.4 42.7 47.3 54.2 13.33
9/15/10 96 2.76 2.81 2.88 32.7 35.9 39.4 42.8 47.5 53.5 13.30
9/16/10 96 2.73 2.78 2.85 31.1 34.0 37.7 43.7 47.7 53.9 13.26
9/17/10 96 2.70 2.75 2.82 30.0 32.3 36.1 42.6 47.4 53.7 13.30
9/18/10 96 2.67 2.71 2.75 28.2 30.2 32.5 42.4 46.5 53.4 13.32
9/19/10 96 2.62 2.67 2.74 26.1 28.6 31.7 43.9 49.8 55.6 13.31
9/20/10 96 2.55 2.60 2.64 23.0 25.0 26.9 40.2 45.2 50.9 13.20
9/21/10 96 2.51 2.55 2.60 21.3 22.9 24.9 32.7 39.6 48.2 13.19
9/22/10 96 2.48 2.51 2.55 20.0 21.2 22.8 34.0 39.0 45.3 13.19
9/23/10 96 2.46 2.48 2.52 19.0 19.9 21.4 38.8 42.6 49.1 13.31
9/24/10 96 2.44 2.45 2.48 18.1 18.8 20.1 40.0 44.3 51.8 13.24
9/25/10 96 2.48 2.69 2.84 20.0 29.4 37.2 39.7 41.0 43.5 13.14
9/26/10 96 2.84 3.97 4.76 37.5 142.8 245.0 43.6 44.8 46.9 13.16
9/27/10 96 3.58 3.96 4.52 92.8 135.3 206.8 43.1 45.2 48.4 13.24
9/28/10 96 3.52 3.68 3.81 87.3 102.0 115.8 41.0 43.1 46.0 13.17
9/29/10 96 3.68 4.10 4.49 101.9 149.9 202.1 43.3 46.6 49.1 13.27
9/30/10 96 3.69 4.00 4.27 103.2 137.4 170.2 46.7 48.7 50.6 13.24
10/1/10 96 3.36 3.52 3.67 73.5 87.3 100.9 41.9 45.3 49.3 13.17
10/2/10 96 3.33 3.48 3.63 70.3 83.8 97.0 45.6 47.0 48.4 13.19
10/3/10 96 3.49 3.60 3.77 84.3 94.5 111.2 41.4 44.5 46.4 13.25
10/4/10 96 3.37 3.44 3.53 73.6 79.6 88.2 42.1 44.0 47.8 13.24
10/5/10 96 3.24 3.30 3.37 63.5 68.0 74.1 36.0 41.7 49.3 13.23
10/6/10 96 3.39 4.83 5.93 75.2 268.6 488.9 36.6 43.2 45.2 13.10
10/7/10 96 3.52 3.78 4.17 86.7 113.3 157.5 37.7 42.6 47.2 13.20
10/8/10 96 3.31 3.40 3.54 69.4 76.7 88.4 40.0 42.0 47.3 13.11
10/9/10 96 3.21 3.29 3.53 61.7 67.4 87.7 40.4 43.2 47.9 13.21
10/10/10 96 3.55 3.82 4.35 89.7 117.6 181.9 40.3 42.8 45.5 13.09
10/11/10 96 3.65 4.04 4.46 99.1 143.0 197.8 40.8 43.5 45.4 13.17
10/12/10 96 3.36 3.50 3.72 73.4 85.7 105.6 38.9 41.6 46.0 13.18
10/13/10 96 3.36 3.83 4.38 73.3 122.3 186.1 40.2 42.5 45.0 13.12
10/14/10 96 3.41 3.63 3.96 77.3 97.9 132.4 39.9 42.1 45.9 13.18
10/15/10 96 3.33 3.41 3.57 70.8 77.8 91.4 40.1 41.4 43.6 13.13
10/16/10 96 3.31 3.37 3.44 69.1 73.8 79.9 36.4 39.6 43.5 13.12
10/17/10 96 3.26 3.31 3.37 65.5 69.3 73.9 39.6 40.2 41.7 13.15
10/18/10 96 3.28 3.86 4.38 66.9 124.2 185.4 40.6 41.1 42.0 13.08
10/19/10 96 3.51 3.72 4.13 86.1 107.2 152.2 41.1 42.3 44.9 13.15
10/20/10 96 3.25 3.38 3.51 64.4 74.9 85.9 38.6 41.1 45.1 13.18
10/21/10 96 3.06 3.17 3.27 50.8 58.4 65.6 30.2 35.2 42.2 13.11
10/22/10 96 2.93 3.01 3.08 42.7 47.5 52.0 31.8 35.7 40.5 13.09
10/23/10 96 2.85 2.90 2.95 38.1 40.6 43.9 39.3 40.4 42.2 13.13
10/24/10 96 2.79 2.83 2.86 34.3 36.5 38.3 39.7 41.7 44.1 13.09
10/25/10 96 2.72 2.75 2.79 30.9 32.7 34.8 39.4 41.6 45.2 13.10
10/26/10 96 2.67 2.70 2.73 28.5 29.9 31.1 36.2 39.6 44.4 13.09
10/27/10 96 2.64 2.66 2.68 26.8 27.8 28.9 36.4 38.6 41.6 13.08
10/28/10 96 2.60 2.63 2.65 25.3 26.5 27.6 36.8 38.0 41.0 13.06
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
10/29/10 96 2.60 2.64 2.83 24.9 27.0 36.5 36.5 37.6 39.9 12.99
10/30/10 96 2.80 3.00 3.28 35.3 47.3 66.4 34.5 38.2 42.5 13.02
10/31/10 96 2.69 2.74 2.81 29.4 32.1 35.5 36.6 37.7 39.6 13.07
11/1/10 96 2.65 2.67 2.71 27.2 28.4 30.2 35.6 37.9 40.3 13.04
11/2/10 96 2.65 3.23 4.04 27.4 71.9 141.8 34.1 39.2 41.8 12.97
11/3/10 96 3.22 3.49 3.86 62.1 85.6 120.8 38.3 41.1 44.0 13.02
11/4/10 96 3.24 4.07 5.18 63.7 156.7 321.0 37.6 38.7 39.7 12.95
11/5/10 96 3.35 3.63 4.12 72.3 98.7 150.8 36.9 39.1 40.6 12.98
11/6/10 96 3.09 3.21 3.37 52.7 61.6 73.6 34.9 37.2 40.1 12.97
11/7/10 96 2.93 3.01 3.10 42.8 47.9 53.7 36.5 38.0 39.9 12.98
11/8/10 96 2.85 2.89 2.95 37.8 40.3 43.8 35.9 37.8 40.6 13.00
11/9/10 96 2.76 2.81 2.86 33.2 35.6 38.2 29.4 33.5 38.0 12.96
11/10/10 96 2.71 2.75 2.78 30.6 32.2 33.8 30.0 32.6 35.6 13.00
11/11/10 96 2.67 2.70 2.73 28.6 29.9 31.4 33.7 34.5 37.1 12.99
11/12/10 96 2.67 2.75 2.98 28.6 32.8 45.4 34.9 37.5 40.0 13.00
11/13/10 96 2.97 3.23 3.92 44.8 63.8 127.1 37.4 41.3 45.7 13.01
11/14/10 96 3.21 3.56 4.07 61.7 92.2 145.2 36.8 39.9 45.6 13.08
11/15/10 96 2.98 3.09 3.23 45.4 52.9 62.6 31.5 36.0 40.6 13.02
11/16/10 96 2.84 2.90 2.99 37.1 41.1 46.2 30.1 30.8 32.5 12.98
11/17/10 96 2.67 2.75 2.84 28.2 32.7 37.5 26.5 28.5 31.7 13.06
11/18/10 96 2.62 2.67 2.74 26.2 28.4 31.9 19.2 22.4 26.8 13.02
11/19/10 96 2.63 2.66 2.70 26.6 28.1 30.0 22.3 28.5 31.1 13.06
11/20/10 96 2.57 2.60 2.65 23.6 24.9 27.2 21.4 25.0 32.8 12.94
11/21/10 96 2.57 2.58 2.60 23.6 24.2 24.9 23.2 28.7 32.0 13.04
11/22/10 96 2.49 2.54 2.57 20.4 22.3 23.5 23.4 29.5 32.9 12.98
11/23/10 96 2.47 2.49 2.50 19.7 20.2 20.6 22.3 25.5 27.7 12.97
11/24/10 96 2.46 2.48 2.50 19.2 19.8 20.6 27.0 29.5 33.1 12.96
11/25/10 96 2.45 2.46 2.48 18.8 19.3 19.9 32.2 35.9 39.2 12.95
11/26/10 96 2.42 2.44 2.46 17.6 18.4 19.2 29.0 32.1 38.2 13.01
11/27/10 96 2.37 2.41 2.43 15.9 17.2 17.9 24.4 28.9 33.7 12.98
11/28/10 96 2.36 2.39 2.42 15.5 16.6 17.6 24.4 27.7 29.0 12.97
11/29/10 96 2.38 2.39 2.40 16.0 16.5 16.7 29.1 30.1 31.4 12.92
11/30/10 96 2.35 2.38 2.39 15.0 15.9 16.4 22.7 27.6 31.5 12.91
12/1/10 96 2.29 2.35 2.40 13.1 15.1 16.9 15.8 18.4 23.0 13.01
12/2/10 96 2.41 2.65 2.75 17.2 27.4 32.3 14.5 16.0 17.4 12.87
12/3/10 96 2.73 2.86 3.24 31.4 38.6 63.3 10.0 11.4 10.0 12.83
12/4/10 96 3.01 3.17 3.32 47.8 58.7 70.1 10.2 21.4 33.0 12.86
12/5/10 96 2.67 3.05 3.31 28.5 51.0 69.0 33.1 36.0 40.1 12.92
12/6/10 96 2.33 2.38 2.64 14.4 16.3 27.1 28.8 32.7 40.0 12.92
12/7/10 96 2.31 2.32 2.34 13.6 14.1 14.6 29.6 31.5 36.2 12.80
12/8/10 96 2.30 2.31 2.32 13.2 13.5 13.9 28.6 31.6 32.8 12.81
12/9/10 96 2.28 2.30 2.32 12.8 13.2 14.0 22.4 26.7 32.0 12.80
12/10/10 96 2.29 2.31 2.34 13.1 13.5 14.6 20.6 21.6 24.7 12.81
12/11/10 96 2.30 2.32 2.38 13.2 14.1 15.9 21.2 21.8 22.5 12.75
12/12/10 96 2.30 2.31 2.34 13.4 13.7 14.5 20.0 21.9 23.3 12.74
12/13/10 96 2.28 2.29 2.31 12.6 13.0 13.5 19.5 20.8 23.0 12.73
12/14/10 96 2.27 2.29 2.31 12.4 12.9 13.6 15.6 18.7 20.3 12.74
12/15/10 96 2.28 2.33 2.58 12.6 14.3 24.1 16.6 17.3 19.4 12.73
12/16/10 96 2.37 2.45 2.61 15.6 18.6 25.5 14.6 16.1 18.7 12.72
12/17/10 96 2.66 2.80 2.96 28.0 35.4 44.5 15.4 16.5 18.2 12.72
12/18/10 96 2.49 2.81 3.11 20.2 36.3 54.5 13.0 15.9 17.9 12.69
12/19/10 96 2.56 2.79 2.96 23.4 34.9 44.4 12.9 14.2 15.5 12.68
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
12/20/10 96 2.29 2.45 2.61 12.9 18.8 25.5 10.0 11.0 9.6 12.66
12/21/10 96 2.40 2.68 3.02 16.8 29.7 48.5 10.0 11.1 10.0 12.65
12/22/10 96 2.21 2.50 3.08 10.4 22.1 52.1 13.4 14.6 16.5 12.66
12/23/10 96 2.24 2.36 2.87 11.4 15.7 38.8 16.8 18.1 19.4 12.68
12/24/10 96 2.19 2.26 2.32 9.8 12.1 13.9 16.3 18.0 21.4 12.67
12/25/10 96 2.11 2.23 2.36 7.7 11.1 15.5 17.8 18.8 20.5 12.67
12/26/10 96 2.11 2.24 2.47 7.7 11.5 19.4 20.3 22.2 23.2 12.68
12/27/10 96 2.12 2.16 2.32 8.0 9.2 14.0 20.1 22.9 25.4 12.68
12/28/10 96 2.14 2.15 2.17 8.5 8.9 9.3 19.3 20.9 23.8 12.66
12/29/10 96 2.13 2.14 2.18 8.2 8.4 9.6 18.8 20.2 22.5 12.65
12/30/10 96 2.12 2.12 2.13 8.0 8.1 8.3 20.2 23.8 29.7 12.66
12/31/10 96 2.12 2.12 2.12 7.9 8.0 8.1 29.7 33.8 36.0 12.72
1/1/11 96 2.10 2.11 2.14 7.6 7.9 8.5 33.8 35.2 36.7 12.72
1/2/11 96 2.09 2.11 2.12 7.2 7.7 8.1 33.5 34.2 36.5 12.71
1/3/11 96 2.10 2.12 2.14 7.6 8.0 8.4 34.6 37.4 40.0 12.72
1/4/11 96 2.12 2.13 2.18 7.9 8.2 9.6 33.8 36.0 40.4 12.71
1/5/11 96 2.14 2.19 2.24 8.7 9.9 11.3 33.0 36.5 38.9 12.71
1/6/11 96 2.11 2.13 2.14 7.8 8.2 8.6 31.3 32.9 35.0 12.69
1/7/11 96 2.10 2.11 2.12 7.6 7.8 8.0 29.3 31.3 32.0 12.68
1/8/11 96 2.09 2.10 2.11 7.3 7.5 7.6 24.4 26.9 31.7 12.74
1/9/11 96 2.07 2.10 2.12 6.8 7.5 7.9 19.1 22.0 25.8 12.73
1/10/11 96 2.09 2.10 2.13 7.3 7.6 8.3 19.9 21.4 24.3 12.72
1/11/11 96 2.10 2.12 2.20 7.5 8.0 10.3 21.4 24.3 27.4 12.77
1/12/11 96 2.06 2.10 2.17 6.6 7.6 9.3 14.7 21.0 27.7 12.80
1/13/11 96 2.11 2.19 2.43 7.7 10.0 17.8 10.0 11.0 9.9 12.73
1/14/11 96 2.44 2.70 3.18 18.3 30.4 59.1 2.9 6.4 9.4 12.65
1/15/11 96 2.41 3.13 3.64 17.2 60.6 97.8 0.0 0.5 3.9 12.70
1/16/11 96 2.45 2.71 3.39 18.8 31.5 75.2 0.0 2.7 9.6 12.63
1/17/11 96 3.43 3.58 3.66 78.8 92.8 100.2 10.0 10.1 9.9 12.68
1/18/11 96 2.34 2.92 3.42 14.5 44.6 78.5 13.4 17.5 20.5 12.68
1/19/11 96 2.09 2.23 2.41 7.4 11.2 17.1 14.8 18.0 22.1 12.68
1/20/11 96 2.10 2.13 2.23 7.4 8.3 11.2 16.2 17.5 20.9 12.67
1/21/11 96 2.03 2.14 2.42 5.7 8.7 17.6 21.1 29.4 34.5 12.70
1/22/11 96 2.07 2.31 3.51 6.7 17.4 86.1 31.2 36.7 39.5 12.75
1/23/11 96 2.16 2.32 2.86 9.1 14.5 38.6 37.6 38.8 39.7 12.76
1/24/11 96 2.11 2.13 2.16 7.7 8.3 9.0 33.8 38.1 41.2 12.75
1/25/11 96 2.10 2.14 2.21 7.5 8.7 10.4 36.0 38.8 41.4 12.76
1/26/11 96 2.14 2.17 2.29 8.4 9.4 13.0 31.5 36.1 41.8 12.74
1/27/11 96 2.18 2.28 2.36 9.8 12.8 15.5 33.0 35.9 41.4 12.73
1/28/11 96 2.11 2.14 2.18 7.7 8.6 9.7 26.2 29.8 35.3 12.78
1/29/11 96 2.05 2.10 2.11 6.2 7.4 7.8 22.2 25.9 30.3 12.68
1/30/11 96 2.05 2.07 2.09 6.3 6.8 7.1 18.4 22.1 24.7 12.65
1/31/11 96 2.07 2.09 2.13 6.9 7.2 8.4 15.8 18.9 23.4 12.66
2/1/11 96 2.04 2.14 3.05 6.0 9.0 50.2 23.7 29.8 39.0 12.73
2/2/11 96 3.14 3.45 3.81 56.6 81.9 115.1 33.8 39.6 43.9 12.71
2/3/11 96 3.15 3.55 3.93 57.0 91.8 129.2 32.5 37.5 41.2 12.69
2/4/11 96 2.68 2.97 3.36 29.0 46.0 73.3 33.8 36.1 42.6 12.77
2/5/11 96 2.45 2.55 2.69 18.7 22.9 29.2 30.4 33.2 37.6 12.81
2/6/11 96 2.35 2.39 2.46 15.0 16.6 18.9 26.5 28.6 31.3 12.74
2/7/11 96 2.30 2.33 2.36 13.2 14.4 15.2 23.7 27.6 31.1 12.77
2/8/11 96 2.28 2.31 2.91 12.6 13.6 41.2 17.0 21.3 26.1 12.66
2/9/11 96 2.35 2.42 2.51 14.9 17.5 21.0 23.4 29.3 33.9 12.83
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
2/10/11 96 2.20 2.27 2.39 10.3 12.3 16.4 33.5 35.5 38.1 12.75
2/11/11 96 2.21 2.23 2.30 10.4 11.0 13.2 32.8 34.5 39.3 12.68
2/12/11 96 2.25 2.27 2.30 11.6 12.4 13.2 31.2 33.7 40.2 12.78
2/13/11 96 2.19 2.22 2.26 9.9 10.9 11.9 24.4 29.7 35.2 12.79
2/14/11 96 2.18 2.22 2.36 9.6 10.9 15.4 10.8 17.1 24.4 12.73
2/15/11 96 2.37 2.83 3.23 15.7 37.8 62.7 10.1 11.4 13.8 13.02
2/16/11 96 3.23 3.46 3.66 63.0 82.0 100.4 10.0 8.8 10.0 12.76
2/17/11 96 3.44 3.61 3.79 80.1 95.3 113.1 10.1 8.2 9.9 12.69
2/18/11 96 3.23 3.38 3.58 62.9 75.1 92.5 10.0 9.5 10.0 12.67
2/19/11 96 2.93 3.07 3.23 42.8 51.6 63.1 10.3 22.1 31.4 12.92
2/20/11 96 2.56 2.73 2.93 23.3 31.6 42.5 18.4 28.5 32.9 12.75
2/21/11 96 2.35 2.44 2.56 15.2 18.3 23.1 14.4 18.4 20.9 12.78
2/22/11 96 2.21 2.28 2.35 10.6 12.6 15.1 16.1 18.6 22.1 12.72
2/23/11 96 2.15 2.18 2.21 8.9 9.7 10.6 10.0 12.1 9.9 12.95
2/24/11 96 2.08 2.12 2.17 7.1 8.1 9.3 10.2 9.4 9.9 12.85
2/25/11 96 2.06 2.07 2.09 6.6 6.9 7.2 11.5 14.7 18.6 13.00
2/26/11 96 2.06 2.06 2.07 6.5 6.6 6.8 19.5 26.0 28.1 13.08
2/27/11 96 2.05 2.06 2.07 6.3 6.5 6.7 10.8 15.9 26.3 13.15
2/28/11 96 2.04 2.05 2.06 6.1 6.2 6.5 10.0 10.9 9.9 13.22
3/1/11 96 2.03 2.04 2.05 5.9 6.0 6.2 10.1 9.3 10.0 13.15
3/2/11 96 2.03 2.03 2.04 5.7 5.9 6.0 10.1 10.0 10.0 13.11
3/3/11 96 2.02 2.03 2.03 5.7 5.8 5.9 11.8 14.0 15.8 13.26
3/4/11 96 2.02 2.02 2.03 5.5 5.7 5.8 10.9 12.9 17.6 13.24
3/5/11 96 2.01 2.02 2.03 5.5 5.6 5.7 15.7 18.5 20.5 13.20
3/6/11 96 2.01 2.02 2.02 5.5 5.5 5.6 16.9 21.3 25.3 13.23
3/7/11 96 2.01 2.01 2.02 5.4 5.4 5.6 13.8 18.3 24.0 13.11
3/8/11 96 2.01 2.01 2.01 5.3 5.4 5.5 18.9 21.3 25.2 13.11
3/9/11 96 2.00 2.00 2.01 5.2 5.3 5.4 19.0 21.7 25.7 13.12
3/10/11 96 2.00 2.00 2.01 5.1 5.2 5.4 14.7 19.5 24.8 13.20
3/11/11 96 1.97 1.99 2.00 4.6 5.1 5.2 10.0 13.0 10.0 13.24
3/12/11 96 1.97 1.97 1.99 4.5 4.7 4.9 10.3 11.9 15.7 13.24
3/13/11 96 1.96 1.98 1.99 4.4 4.7 5.0 14.8 16.6 20.0 13.32
3/14/11 96 1.96 1.98 2.00 4.4 4.7 5.2 20.0 21.2 26.8 13.32
3/15/11 96 1.98 1.98 1.99 4.7 4.8 4.9 25.4 27.4 31.2 13.35
3/16/11 96 1.98 1.98 1.99 4.7 4.8 5.0 29.0 31.5 36.2 13.30
3/17/11 96 1.97 1.98 1.98 4.6 4.7 4.8 31.1 34.2 38.6 12.97
3/18/11 96 1.97 1.97 1.98 4.6 4.7 4.8 24.0 30.2 42.4 12.94
3/19/11 96 1.97 1.97 1.98 4.6 4.6 4.8 22.3 27.7 35.3 12.87
3/20/11 96 1.97 1.97 1.97 4.5 4.6 4.6 24.1 26.6 30.8 12.89
3/21/11 96 1.96 1.97 1.97 4.5 4.5 4.6 23.6 27.5 33.4 12.86
3/22/11 96 1.96 1.97 1.97 4.4 4.5 4.6 19.8 25.8 34.0 12.89
3/23/11 96 1.96 1.96 1.97 4.4 4.5 4.5 27.6 32.8 39.0 12.96
3/24/11 96 1.96 1.96 1.97 4.4 4.5 4.5 28.0 32.8 40.7 12.97
3/25/11 96 1.96 1.97 1.97 4.4 4.5 4.6 30.6 34.2 41.3 12.98
3/26/11 96 1.96 1.97 1.98 4.4 4.6 4.8 32.0 35.7 42.8 13.00
3/27/11 96 1.98 1.99 2.00 4.7 4.9 5.1 29.6 34.9 43.9 12.97
3/28/11 96 1.99 2.03 2.07 4.9 6.0 6.7 32.5 35.3 41.0 12.96
3/29/11 96 2.05 2.06 2.08 6.2 6.6 7.0 30.6 35.7 44.9 12.98
3/30/11 96 2.04 2.06 2.07 6.1 6.5 6.8 33.3 36.6 42.9 12.99
3/31/11 96 2.08 2.15 2.19 6.9 8.9 10.0 39.1 41.4 45.4 13.02
4/1/11 96 2.12 2.14 2.16 8.0 8.6 9.0 37.4 41.0 47.9 13.03
4/2/11 96 2.08 2.11 2.13 7.0 7.7 8.2 32.8 37.4 45.3 12.99
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
4/3/11 96 2.08 2.13 2.17 7.0 8.2 9.2 37.9 40.3 46.8 13.02
4/4/11 96 2.08 2.10 2.12 6.9 7.5 8.1 34.1 37.8 46.8 12.99
4/5/11 96 2.06 2.07 2.08 6.5 6.8 7.0 32.6 37.7 47.4 13.01
4/6/11 96 2.05 2.06 2.08 6.3 6.6 6.9 25.6 33.6 46.6 12.97
4/7/11 96 2.04 2.05 2.05 6.2 6.3 6.4 30.7 36.9 45.2 13.00
4/8/11 96 2.03 2.04 2.05 5.8 6.1 6.3 35.8 39.7 46.0 13.00
4/9/11 96 2.04 2.05 2.06 6.0 6.3 6.6 36.5 40.0 47.6 13.01
4/10/11 96 2.02 2.03 2.04 5.7 5.9 6.1 34.9 38.9 44.7 13.00
4/11/11 96 2.01 2.02 2.03 5.5 5.7 5.7 30.8 35.9 45.9 12.99
4/12/11 96 2.01 2.01 2.02 5.4 5.5 5.6 31.9 36.8 45.2 12.98
4/13/11 96 2.01 2.01 2.02 5.4 5.5 5.6 34.8 39.9 46.5 13.01
4/14/11 96 2.01 2.08 2.12 5.5 6.9 7.9 32.1 41.4 52.2 13.02
4/15/11 96 2.09 2.12 2.14 7.1 8.0 8.6 37.6 43.2 54.3 13.03
4/16/11 96 2.08 2.10 2.12 7.0 7.6 7.9 31.3 38.4 46.8 12.98
4/17/11 96 2.06 2.08 2.09 6.6 7.0 7.1 27.2 37.0 49.9 12.98
4/18/11 96 2.06 2.08 2.10 6.6 7.0 7.4 31.1 39.2 55.8 13.00
4/19/11 96 2.05 2.07 2.09 6.3 6.8 7.2 26.5 36.0 51.0 12.97
4/20/11 96 2.05 2.07 2.09 6.2 6.9 7.3 32.7 40.0 57.8 13.00
4/21/11 96 2.08 2.09 2.09 7.0 7.2 7.3 35.8 41.2 56.9 13.02
4/22/11 96 2.07 2.08 2.09 6.7 7.0 7.2 37.8 41.7 51.5 13.01
4/23/11 96 2.06 2.08 2.09 6.6 7.0 7.3 40.9 44.5 50.5 13.01
4/24/11 96 2.08 2.15 2.20 7.0 8.8 10.2 32.6 40.9 51.4 12.98
4/25/11 96 2.14 2.23 2.29 8.6 11.2 13.1 37.9 46.0 67.6 13.04
4/26/11 96 2.25 2.37 2.45 11.7 16.0 18.6 40.4 46.7 68.2 13.03
4/27/11 96 2.40 2.46 2.51 16.9 19.2 21.3 29.7 41.6 68.4 12.98
4/28/11 96 2.38 2.46 2.53 16.2 19.1 21.8 30.5 41.5 69.2 12.96
4/29/11 96 2.41 2.56 2.67 17.3 23.4 28.4 36.1 47.3 80.2 13.03
4/30/11 96 2.42 2.48 2.54 17.5 20.1 22.6 41.3 45.0 52.7 13.01
5/1/11 96 2.35 2.39 2.47 15.1 16.6 19.4 38.9 46.1 58.3 13.03
5/2/11 96 2.44 2.50 2.69 18.5 20.9 29.4 38.2 47.7 74.5 13.22
5/3/11 96 2.45 2.73 2.89 18.7 31.5 40.2 39.4 47.1 58.6 13.41
5/4/11 96 2.74 2.81 2.89 31.8 35.6 40.0 37.8 40.3 44.4 13.39
5/5/11 96 2.71 2.80 2.96 30.4 35.3 44.5 36.3 44.2 56.5 13.41
5/6/11 96 2.93 3.01 3.17 42.5 48.0 58.7 38.7 43.0 50.0 13.39
5/7/11 96 2.93 3.08 3.27 42.8 52.3 65.6 37.9 46.1 75.2 13.41
5/8/11 96 3.00 3.10 3.26 46.6 53.4 65.5 36.4 46.9 67.6 13.41
5/9/11 96 2.92 2.99 3.12 41.8 46.4 54.7 37.5 46.8 60.9 13.42
5/10/11 96 2.82 2.87 2.97 36.1 39.3 45.0 34.9 43.0 51.4 13.42
5/11/11 96 2.81 2.86 2.98 35.9 38.6 45.9 38.5 47.3 73.3 13.41
5/12/11 96 2.94 2.98 3.03 43.4 45.7 48.9 38.3 42.7 49.3 13.38
5/13/11 96 2.90 2.96 3.03 40.5 44.2 48.7 37.4 45.2 65.0 13.42
5/14/11 96 2.93 3.03 3.27 42.4 49.0 66.3 35.7 47.9 82.0 13.36
5/15/11 96 3.06 3.17 3.31 50.8 58.7 69.1 33.6 47.3 81.3 13.30
5/16/11 96 3.10 3.21 3.35 53.6 61.5 72.0 34.5 49.6 90.6 13.34
5/17/11 96 3.17 3.31 3.56 58.2 69.1 90.7 39.3 52.2 85.9 13.40
5/18/11 96 3.45 3.50 3.56 80.4 85.3 90.9 42.8 48.5 71.4 13.39
5/19/11 96 3.41 3.51 3.71 76.9 86.3 105.0 40.2 45.5 56.1 13.37
5/20/11 96 3.65 3.76 3.95 99.5 110.3 130.9 39.7 44.6 61.3 13.39
5/21/11 96 3.64 3.78 3.93 97.7 112.5 128.7 36.6 43.8 52.9 13.39
5/22/11 96 3.66 3.76 3.87 100.3 110.6 122.0 38.6 43.6 51.3 13.38
5/23/11 96 3.62 3.72 3.87 95.8 106.5 121.8 39.8 42.4 47.2 13.33
5/24/11 96 3.70 4.02 4.45 104.0 141.2 195.7 39.4 43.6 51.0 13.40
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
5/25/11 96 4.10 4.26 4.44 149.4 169.9 194.0 39.0 45.7 69.2 13.38
5/26/11 96 4.11 4.37 4.72 150.2 186.3 236.9 38.7 47.7 71.4 13.32
5/27/11 96 4.15 4.41 4.67 154.7 191.4 230.3 38.8 48.6 78.6 13.38
5/28/11 96 4.30 4.42 4.60 175.4 192.6 219.1 41.8 45.5 50.9 13.36
5/29/11 96 4.14 4.31 4.52 154.3 176.5 206.5 41.2 50.0 77.9 13.37
5/30/11 96 4.08 4.37 4.73 146.3 185.1 239.4 39.5 49.6 77.7 13.37
5/31/11 96 4.37 4.58 4.88 183.9 216.3 264.6 40.0 51.3 83.3 13.31
6/1/11 96 4.40 4.61 4.81 189.3 219.7 253.3 40.7 51.4 80.6 13.31
6/2/11 96 4.08 4.26 4.67 146.8 170.8 229.4 42.2 48.4 60.5 13.36
6/3/11 96 4.04 4.11 4.22 142.0 150.4 163.9 44.1 47.9 52.1 13.33
6/4/11 96 3.97 4.09 4.20 133.1 148.3 162.0 42.0 47.9 55.7 13.39
6/5/11 96 3.77 3.90 4.02 111.4 125.9 139.2 43.4 49.3 64.8 13.38
6/6/11 96 3.79 3.92 4.08 113.5 127.9 146.7 42.7 52.7 83.1 13.38
6/7/11 96 3.83 4.08 4.44 117.8 148.1 195.0 40.3 53.7 90.8 13.30
6/8/11 96 4.08 4.21 4.43 146.1 162.8 193.3 46.4 50.0 54.6 13.40
6/9/11 96 3.83 3.95 4.12 117.8 130.8 151.8 45.2 49.9 58.4 13.36
6/10/11 96 3.68 3.76 3.86 102.3 110.4 121.2 44.3 51.3 62.8 13.40
6/11/11 96 3.62 3.70 3.81 96.6 104.2 115.8 44.9 51.3 61.5 13.42
6/12/11 96 3.56 3.65 3.76 90.8 99.1 109.7 44.5 54.3 89.9 13.38
6/13/11 96 3.56 3.68 3.87 90.2 102.0 121.8 41.6 52.0 70.4 13.38
6/14/11 96 3.83 3.96 4.26 117.4 133.1 168.8 44.5 53.3 84.3 13.39
6/15/11 96 3.91 4.05 4.26 126.8 143.1 169.1 44.1 50.9 62.7 13.42
6/16/11 96 3.70 3.82 3.97 104.4 117.1 132.7 42.3 53.3 83.4 13.42
6/17/11 96 3.68 3.79 3.89 102.3 113.4 124.6 41.2 52.1 73.7 13.39
6/18/11 96 3.70 3.86 4.14 103.9 121.3 153.7 44.7 50.8 66.7 13.38
6/19/11 96 4.02 4.14 4.26 138.6 154.3 169.8 45.2 48.6 55.5 13.32
6/20/11 96 3.85 3.95 4.06 119.3 131.4 143.5 44.3 51.5 67.2 13.39
6/21/11 96 3.81 3.90 4.03 115.7 125.7 140.3 43.8 51.6 71.3 13.40
6/22/11 96 3.71 3.85 4.02 104.8 119.5 139.1 43.2 54.5 84.3 13.38
6/23/11 96 3.70 3.89 4.15 104.1 125.0 155.3 42.1 56.1 91.9 13.35
6/24/11 96 3.82 4.03 4.32 116.6 141.0 177.6 45.0 56.4 92.9 13.39
6/25/11 96 4.00 4.11 4.37 136.2 150.8 183.9 47.4 51.9 57.2 13.36
6/26/11 96 3.91 3.99 4.10 126.0 136.0 148.4 47.2 52.4 59.1 13.37
6/27/11 96 3.90 4.04 4.25 125.6 141.4 168.2 47.5 60.1 95.6 13.37
6/28/11 96 3.98 4.06 4.22 135.0 144.2 163.6 49.3 54.8 76.1 13.36
6/29/11 96 3.78 3.90 4.02 112.3 125.5 139.4 47.0 53.4 63.5 13.40
6/30/11 96 3.64 3.73 3.87 97.9 106.8 122.5 47.7 54.2 69.1 13.40
7/1/11 96 3.57 3.63 3.71 91.5 97.7 105.0 45.4 56.4 83.0 13.21
7/2/11 96 3.54 3.60 3.68 88.7 94.1 101.6 44.5 54.9 85.2 12.98
7/3/11 96 3.55 3.65 3.76 89.6 98.8 110.1 48.0 58.6 92.1 12.99
7/4/11 96 3.67 3.74 3.80 101.5 108.6 114.9 48.2 56.1 76.4 13.00
7/5/11 96 3.53 3.63 3.73 88.2 97.1 106.9 45.7 54.3 78.4 12.97
7/6/11 96 3.50 3.58 3.68 85.3 92.6 101.6 45.8 55.5 83.7 12.98
7/7/11 96 3.58 3.70 3.80 92.6 104.7 113.9 45.8 53.7 81.0 12.96
7/8/11 96 3.49 3.58 3.74 84.4 92.9 107.8 42.3 52.8 80.9 12.96
7/9/11 96 3.48 3.53 3.59 83.2 88.3 93.5 48.5 56.5 81.6 12.97
7/10/11 96 3.51 3.57 3.67 85.8 91.9 100.8 49.0 57.5 81.7 12.96
7/11/11 96 3.52 3.66 3.89 86.6 100.7 123.9 45.4 58.3 91.2 12.92
7/12/11 96 3.63 3.81 4.06 97.1 116.0 143.8 47.1 61.3 96.9 12.95
7/13/11 96 3.72 3.89 4.03 106.6 124.8 140.9 48.4 62.0 96.4 12.95
7/14/11 96 3.71 3.82 4.01 105.3 117.3 137.5 52.6 55.1 58.4 12.91
7/15/11 96 3.62 3.68 3.78 95.8 102.3 112.5 50.9 56.6 63.7 12.96
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
7/16/11 96 3.56 3.64 3.72 90.9 98.0 106.6 50.5 59.3 75.7 12.97
7/17/11 96 3.58 3.66 3.76 92.8 99.9 109.8 51.6 58.7 71.9 12.96
7/18/11 96 3.58 3.65 3.76 92.8 99.6 110.5 52.6 57.1 62.9 12.95
7/19/11 96 3.52 3.57 3.63 87.3 91.5 97.4 51.6 58.3 82.3 12.96
7/20/11 96 3.40 3.48 3.59 76.2 83.3 93.3 50.1 57.6 75.9 12.96
7/21/11 96 3.37 3.44 3.59 74.3 80.4 93.5 100.7 61.9 99.7 12.96
7/22/11 96 3.41 3.50 3.62 77.1 85.4 95.9 100.2 63.2 99.7 12.96
7/23/11 96 3.46 3.54 3.63 81.8 88.5 97.3 100.1 64.8 99.7 13.00
7/24/11 96 3.56 3.64 3.76 90.3 98.3 110.7 53.3 57.6 60.3 12.98
7/25/11 96 3.57 3.63 3.77 91.1 97.7 110.9 52.1 57.0 74.9 12.98
7/26/11 96 3.45 3.66 4.11 80.6 101.9 150.4 49.9 52.7 54.9 12.94
7/27/11 96 3.51 3.68 4.07 86.0 103.0 145.7 48.4 52.9 61.0 12.91
7/28/11 96 3.49 3.69 3.98 84.3 103.6 134.8 47.7 52.5 59.2 12.93
7/29/11 96 3.53 3.61 3.71 87.8 95.4 105.3 49.3 52.3 58.3 12.88
7/30/11 96 3.37 3.45 3.59 74.2 80.5 93.6 47.3 57.7 91.1 12.95
7/31/11 96 3.35 3.39 3.45 72.0 75.4 80.7 51.5 56.4 65.6 12.93
8/1/11 96 3.35 3.47 3.64 72.2 83.1 98.0 53.3 56.7 67.2 12.91
8/2/11 96 3.31 3.39 3.55 69.2 75.6 89.8 51.8 56.9 64.5 12.92
8/3/11 96 3.24 3.29 3.33 63.9 67.5 70.7 51.6 58.7 71.2 12.93
8/4/11 96 3.28 3.32 3.36 66.5 70.0 73.1 50.9 53.1 57.0 12.86
8/5/11 96 3.26 3.32 3.39 65.3 69.9 75.7 51.0 55.7 64.4 12.90
8/6/11 96 3.20 3.25 3.31 61.0 64.6 68.8 52.3 56.6 64.1 12.91
8/7/11 96 3.08 3.15 3.22 52.3 56.7 61.9 49.7 57.0 66.9 12.91
8/8/11 96 2.99 3.04 3.09 46.5 49.2 52.6 48.9 54.9 64.4 12.89
8/9/11 96 2.96 3.00 3.03 44.3 46.7 49.1 50.6 56.4 64.0 12.90
8/10/11 96 2.92 2.95 2.98 42.1 43.6 45.8 48.8 54.8 61.9 12.88
8/11/11 96 2.94 3.41 3.94 42.9 79.7 129.5 46.7 49.2 52.7 12.86
8/12/11 96 3.53 3.76 3.96 87.9 111.0 131.7 45.5 48.5 53.5 12.88
8/13/11 96 3.29 3.38 3.54 67.3 74.9 88.7 45.3 51.4 60.2 12.88
8/14/11 96 3.22 3.35 3.68 61.9 72.9 102.0 48.3 51.2 55.9 12.89
8/15/11 96 3.59 3.77 4.05 93.0 112.2 142.4 45.7 48.3 50.4 12.83
8/16/11 96 3.59 3.78 4.00 93.1 113.2 136.6 45.1 48.1 52.5 12.87
8/17/11 96 3.32 3.42 3.58 70.1 78.3 92.3 46.8 51.5 60.0 12.89
8/18/11 96 3.22 3.26 3.32 62.2 65.3 70.0 49.5 52.6 58.1 12.86
8/19/11 96 3.21 3.43 3.70 61.7 79.6 103.8 47.6 49.0 51.0 12.83
8/20/11 96 3.71 4.87 5.52 104.9 268.7 390.5 46.9 51.2 61.9 12.85
8/21/11 96 4.44 4.88 5.73 194.7 267.1 439.7 48.0 49.8 52.2 12.87
8/22/11 96 4.19 4.34 4.44 160.8 180.2 194.0 47.4 48.6 50.7 12.82
8/23/11 96 3.93 4.24 4.60 128.5 167.6 219.1 46.6 49.4 52.5 12.85
8/24/11 96 3.62 3.73 3.91 96.1 107.4 126.6 44.9 48.8 56.7 12.84
8/25/11 96 3.42 3.55 3.73 77.8 89.6 107.6 46.7 50.0 56.4 12.86
8/26/11 96 3.38 3.43 3.53 75.1 79.2 87.9 46.0 47.3 49.6 12.79
8/27/11 96 3.31 3.37 3.44 69.0 74.2 79.6 45.8 48.3 52.1 12.82
8/28/11 96 3.32 3.36 3.43 70.0 73.0 79.3 45.9 48.5 53.4 12.83
8/29/11 96 3.30 3.36 3.46 68.3 73.3 81.3 47.4 50.6 56.4 12.85
8/30/11 96 3.17 3.25 3.32 58.8 64.1 69.7 47.7 50.5 54.8 12.83
8/31/11 96 3.08 3.13 3.19 52.3 55.4 60.2 47.4 50.5 54.9 12.82
9/1/11 96 3.10 3.34 3.54 53.4 71.6 88.9 44.3 47.9 53.6 12.83
9/2/11 96 3.14 3.27 3.63 56.3 66.3 96.7 43.5 47.4 51.2 12.75
9/3/11 96 3.63 4.04 4.56 97.5 145.2 212.8 45.8 49.1 52.3 12.80
9/4/11 96 3.75 4.02 4.40 109.2 140.9 189.3 45.8 48.5 53.6 12.84
9/5/11 96 3.55 3.81 5.08 89.5 120.4 301.6 45.2 47.4 50.0 12.78
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study
Polarconsult Alaska, Inc.
Record Recorded Stage (ft, station datum)Calculated Flow (cfs) Air Temperature (F) (Note 1) Battery
Count Minimum Average Maximum Minimum Average Maximum Minimum Average Maximum VoltageDate Notes
9/6/11 96 4.21 4.64 5.53 163.4 229.4 393.9 44.5 47.4 51.7 12.80
9/7/11 96 3.80 4.20 4.66 114.3 163.7 227.9 44.4 49.5 55.5 12.81
9/8/11 96 3.50 3.62 3.88 84.7 96.4 122.9 41.3 45.9 49.4 12.79
9/9/11 96 3.87 4.37 4.77 122.4 185.6 245.7 46.3 50.3 53.7 12.80
9/10/11 96 3.49 3.71 4.02 84.3 105.7 139.3 42.6 47.2 53.6 12.82
9/11/11 96 3.28 3.39 3.52 67.1 75.6 87.1 38.3 43.2 49.2 12.74
9/12/11 96 3.15 3.21 3.30 57.3 61.5 68.1 42.9 47.9 54.7 12.74
9/13/11 96 3.12 3.23 3.34 55.1 63.2 71.3 46.7 49.8 55.5 12.94
9/14/11 96 3.28 3.57 4.02 67.1 93.4 139.4 48.0 50.2 52.6 13.23
9/15/11 96 3.32 3.53 4.00 69.5 88.8 136.6 44.6 47.8 53.0 13.31
9/16/11 96 3.14 3.23 3.33 56.1 62.6 70.6 44.5 47.1 52.7 13.31
9/17/11 96 3.03 3.10 3.15 48.7 53.4 56.8 41.8 46.6 52.6 13.29
9/18/11 96 2.94 2.98 3.04 42.9 45.9 49.7 39.8 46.2 54.6 13.28
9/19/11 96 2.92 3.01 3.60 41.7 48.2 94.4 45.7 49.5 54.5 13.24
9/20/11 96 3.67 4.60 5.05 100.9 222.4 296.0 44.1 45.9 49.0 13.20
9/21/11 96 4.15 4.61 5.86 155.4 227.3 470.7 44.7 45.7 46.8 13.14
9/22/11 96 3.99 4.61 5.94 136.1 228.7 491.2 41.6 45.6 49.5 13.29
9/23/11 96 3.60 3.79 3.99 94.1 114.0 136.0 41.9 44.7 46.7 13.27
9/24/11 96 3.55 3.81 4.07 89.3 116.0 145.2 40.0 46.1 51.9 13.30
9/25/11 96 3.28 3.41 3.57 66.4 77.8 91.9 37.6 42.5 49.4 13.26
9/26/11 96 3.12 3.21 3.30 54.9 61.9 68.6 41.7 43.8 47.0 13.20
9/27/11 96 2.98 3.06 3.15 45.6 51.0 56.9 41.1 45.3 49.9 13.28
9/28/11 96 3.05 3.47 3.95 50.2 85.1 131.1 41.2 43.9 46.7 13.09
9/29/11 96 3.58 3.72 3.88 92.1 106.4 123.5 38.8 41.5 44.8 13.25
9/30/11 96 3.32 3.44 3.59 69.8 79.7 93.7 41.7 44.2 48.0 13.26
10/1/11 96 3.20 3.33 3.46 60.4 70.6 81.8 36.3 43.6 48.1 13.26
10/2/11 96 3.04 3.12 3.22 49.3 55.2 62.4 31.6 35.8 41.9 13.16
10/3/11 96 2.94 2.99 3.06 43.0 46.6 51.0 32.7 38.0 44.7 13.25
10/4/11 96 2.85 2.90 2.95 38.1 41.0 44.0 36.0 40.7 46.6 13.20
10/5/11 96 2.82 2.85 2.90 36.0 37.8 40.8 38.6 42.0 45.1 13.27
10/6/11 96 2.80 2.87 2.94 35.3 38.8 43.0 42.7 45.4 48.7 13.22
10/7/11 96 2.90 3.24 3.49 40.8 64.5 84.5 44.1 46.0 48.5 13.23
10/8/11 96 3.03 3.17 3.35 48.9 58.8 72.1 41.1 44.0 47.6 13.23
10/9/11 96 2.99 3.07 3.20 46.2 51.3 60.5 41.1 42.8 46.6 13.24
10/10/11 96 2.94 3.04 3.13 43.1 49.7 55.7 38.5 41.5 45.4 13.25
10/11/11 96 2.85 2.89 2.96 37.8 40.5 44.5 40.7 43.4 48.4 13.23
10/12/11 56 2.86 2.90 2.96 38.3 41.1 44.5 40.9 41.7 43.3 13.12 (4)
Notes:
1. Air temperature is measured on-board the data logger, and can be affected by logger operations or solar gain
on the logger enclosure.
2. Gauge installation.
3. Power supply changed.
4. Most recent download.
November 2011 - Final Report
Appendix C
Section C.4
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report C‐11
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report
APPENDIX D – RESOURCE DATA AND ANALYSIS
D.1: Maximum Probable Flood page D‐1
D.2: Geotechnical Considerations page D‐2
D.3: Tsunami Hazards page D‐2
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report D‐1
D.1 Maximum Probable Flood
Determining the maximum probable flood for Burro Creek is important for designing the in‐
stream diversion structure so it can withstand flood flows. Existing data from the gauging
station and extended flow record is compared with U.S. Geological Survey (USGS) statistical
models for southeast Alaska streams to develop initial estimates of the 100‐year flood flows for
Burro Creek.
The USGS has developed statistical models to estimate the maximum probable floods for
streams in southeast Alaska. These models are developed based on stream gauging data
throughout the region, and specific parameters for the drainage basin of the stream of interest. 7
USGS model input parameters and flood flow estimates are summarized in Table D‐1. The
estimated 2‐year flood flows in Table D‐1 are approximately 131% of the highest observed flows
recorded at Burro Creek in 1.8 years of measurements. This is reasonable agreement, given the
accuracy of the USGS estimation method, the length of record at the gauging station, and the
lack of flow measurements at peak flow conditions. The estimated 100‐year maximum probable
flood flows are used for the conceptual designs described in this feasibility study.
Table D‐1: Maximum Probable Floods at Burro Creek
Parameter Burro Creek
Basin Area (square miles) 12.39
Mean Annual Precipitation (inches) (1) 80
Percentage of Basin as Storage (lakes, ponds) 0%
Mean Minimum January Temperature (°F) (1) +4°F
Estimated 500‐year flood 2,364 cfs
Estimated 100‐year flood (Initial Estimate of Design Flood)1,815 cfs
Estimated 25‐year flood 1,390 cfs
Estimated 2‐year flood 641 cfs
Maximum Recorded Flow (Dec. 2009 – Oct. 2011) (2) 491 cfs
Source: Polarconsult Alaska, Inc., 2011.
(1) Data are from source maps specified in the USGS publication.
(2) Maximum flow is calculated from recorded stage data and the gauging station’s rating curve. This calculated
flow is well outside the range of measured flows used to develop the stage‐discharge curve, and may have
significant extrapolation error.
7 See USGS Water Resources Investigation Report 2003‐4188.
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D.2 Geotechnical Considerations
The prevalence of shallow bedrock throughout the project area precludes cost‐effective
trenching for burial of pipelines and power cables in some areas. Partial burial, on‐grade,
and/or above‐grade pipelines are viable project options. Similarly, on‐grade or shallow burial
cables in conduit are practical options for power and communications.
Access trails in certain areas may require removal of rock. To reduce construction costs,
geotechnical subsurface investigation is recommended before access alignments are finalized to
reduce the amount of blasting and ripping required.
D.2.1 Typical Vegetation
The project area is generally forested by large conifers growing in shallow soils overlaying
weathered and fractured rock. Mixed conifer and deciduous vegetation tends to be prevalent
where the grades are moderate and thicker soil strata occurs.
D.3 Tsunami Hazards
The only feature of a hydro project at Burro Creek that would be exposed to tsunami hazard is
the powerhouse. All of the proposed powerhouse sites are away from the coast, at elevations of
50 or more feet above sea level. Tsunami hazard for these sites is considered minimal.
Tsunamis can be generated from distant seismic events such as the March 1964 Alaska
earthquake or the March 2011 Japan earthquake. Tsunamis can also be generated by local
events, such as landslides into nearby waters or submarine landslides.
The tsunami energy from distant sources cannot generally propagate into upper Lynn Canal
and still cause tsunamis of concern to this project. Locally sourced tsunamis do occur in upper
Lynn Canal, due to submarine and upland landslides or mass wasting events. Burro Creek is
potentially exposed to tsunamis from events at the alluvial fan of the Skagway River (Skagway
waterfront) or the east shore of Lynn Canal south approximately one mile from Skagway.
Tsunami hazard should be assessed during the design phase of projects with powerhouses sited
north of the dock or below the falls.
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APPENDIX E – ENVIRONMENTAL CONSIDERATIONS
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E.1 THREATENED AND ENDANGERED SPECIES
Threatened or endangered species, and those species designated as candidates but not yet listed
to those categories, are the Kittlitz’s murrelet, the yellow-billed loon, and possibly the short-
tailed albatross.
Preliminary consultation with the U.S. Fish and Wildlife Service indicates that this project is not
expected to impact any of these species.
E.2 FISHERIES AND WILDLIFE
Burro Creek is not listed as an anadromous stream in the Alaska Department of Fish and
Game’s catalog of anadromous streams.8 The creek drops from high elevations, and the lower
reaches which might allow fish passage run only a short distance to the shore. Much of the
stream bed is bedrock, and does not make good fish rearing habitat. However, Dolly Varden
have occasionally been reported in the creek over the years, and salmon occasionally visit the
lower reaches. The habitat for these species occurs between the waterfall at mile 0.13 and
tidewater. This reach of the creek formerly housed a salmon hatchery, so it might be expected
that some salmon visit the area, but the habitat is not conducive to spawning. A stream survey
is recommended prior to project construction.
The project is not expected to have a significant impact on fisheries and wildlife resources.
In the event that the limited utilization of the lower reaches of Burro Creek by Dolly Varden and
salmon result in minimum flow requirements in the habitat reach, the generation potential of
the project could be curtailed.
If the powerhouse were located above the waterfall at site ‘A’, no generation curtailment would
be needed due to an in-stream flow requirement, as the entire habitat reach would be located
downstream of the hydro project, and habitat flows would be unchanged from natural
conditions.
If the powerhouse were located at sites ‘B’, ‘C’, or ‘D’, some generation curtailment would result
from a minimum in-stream flow requirement. This curtailment would depend on the amount
and timing of the in-stream flow requirement. The financial impact of this curtailment would
be bracketed by the ‘full sales’ and ‘partial sales’ scenarios presented in Appendix H, Table H-2.
E.3 WATER AND AIR QUALITY
The project will not have a significant negative impact on air or water quality. By reducing
diesel combustion in the Skagway Area, and possibly powering cruise ships while in port in
Skagway, it will actually improve air quality.
E.4 WETLAND AND PROTECTED AREAS
Based on field reconnaissance in 2009, 2010, and 2011, project configurations located on USS
1560 will not require filling wetland areas. Projects located on Federal land above USS 1560
8 Catalog and Atlas of Waters Important for the Spawning, Rearing or Migration of Anadromous Fishes, Alaska
Department of Fish and Game, 2010. http://www.sf.adfg.state.ak.us/SARR/awc/
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may require filling of small localized wetlands that occur along the penstock / access route. The
project is not expected to have a significant impact on wetlands or protected areas.
E.5 ARCHAEOLOGICAL AND HISTORICAL RESOURCES
No archaeological or historical resources are known in the Burro Creek area. The State
Historical Preservation Office will be consulted during the permitting process to determine if
any historical or archaeological resources exist in the area. In addition, local Native groups will
be consulted regarding cultural resources in the area.
E.6 LAND DEVELOPMENT CONSIDERATIONS
This project is expected to be built mostly on private land, with possible extension to US Bureau
of Land Management (BLM) lands on the mountain slope above the private land. No
significant impacts to land development in the area are expected to occur from this
development.
E.7 TELECOMMUNICATIONS AND AVIATION CONSIDERATIONS
The project will not create significant impacts to telecommunications or aviation resources.
E.8 VISUAL AND AESTHETIC RESOURCES
Although Burro Creek falls is beautiful, it cannot be seen off the property due to dense forest.
Development of the upgrade would require some tree removal which could allow the
development to be seen from a distance. Reasonable efforts will be made to minimize visual
impacts of the project. Depending on final siting, the new powerhouse could be visible by sea,
air, and possibly from the Skagway waterfront with the use of powerful binoculars or spotting
scopes. The new powerhouse would be designed to blend in with the surroundings. It would
appear as another outbuilding similar to the buildings already existing along the shore at Burro
Creek. No significant impacts to visual or aesthetic resources would occur from this project.
E.9 MITIGATION MEASURES
No impacts warranting mitigation are known at this time.
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APPENDIX F – PERMITTING INFORMATION
F.1: Federal Permits pages F‐1 to F‐2
F.2: State Permits pages F‐2
F.3: Local Permits pages F‐3
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F.1 FEDERAL PERMITS
F.1.1 Federal Energy Regulatory Commission
Most hydroelectric projects in Alaska are licensed by the Federal Energy Regulatory
Commission (FERC). These licenses determine how to allocate stream flows between energy
generation and other beneficial uses recognized by the Federal Power Act, and other applicable
laws. Small hydroelectric projects (under 5 MW) may be exempted from obtaining a FERC
license under certain conditions, such as the use of a natural water feature, and control over all
non‐Federal lands impacted by the project.
An applicant must file for a FERC exemption application which includes such documentation
as:
a detailed project description;
proof of property ownership or rights obtained for use;
project schematics and maps;
an environmental report outlining the project areas:
o flora and fauna,
o land and water uses,
o recreational uses,
o historical and archeological resources,
o water quality and quantity,
o scenic and aesthetic resources,
o and endangered or threatened species, and critical habitats.
Description of expected environmental impacts;
Proof of consultation with pertinent agencies, including having supplied such agencies
with the draft application and required studies, and having received and addressed
agency comments.
If a FERC license is required for the project, all State and Federal permitting efforts will be
managed through that licensing process. Projects exempted from FERC licensing must use
normal State and Federal permitting processes.
To determine if the project is eligible for an exemption, a Declaration of Intent should be filed,
and FERC will determine whether the project must obtain an exemption or a license.
F.1.2 U.S. Bureau of Land Management
Project configurations utilizing diversion sites 1, 2 or 3 place the project onto Federal land
managed by the U.S. Bureau of Land Management (BLM). Land use permits must be obtained
for that use.
F.1.3 U.S. Forest Service
The project area is not located within the Tongass National Forest, so is not required to obtain
land use permits from that agency.
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F.1.4 U.S. Army Corps of Engineers
Army Corps of Engineers (COE) permits must be obtained for work within waters of the U.S.,
which includes the diversion structure in Burro Creek and the submarine cable from Burro
Creek to Skagway. COE permits are also required for work in wetlands. No wetland work is
necessary for projects with diversions at sites 4 or 5 (on USS 1560), however projects with
diversions at sites 1, 2 or 3 (on BLM land above USS 1560) will require some work in wetlands.
If this project is exempted from FERC licensing (or ruled non‐jurisdictional because it is located
entirely on USS 1560), it is expected to be eligible for a Nation Wide Permit #17 for hydroelectric
projects. Otherwise, the project must be permitted as part of the FERC licensing process.
F.1.5 U.S. Environmental Protection Agency
A stormwater pollution prevention plan will be required for construction of this project.
F.1.6 Federal Aviation Administration
None of the project alternatives will present hazards to aviation.
F.1.7 U.S. Fish and Wildlife Service
Preliminary consultation with the U.S. Fish and Wildlife Service indicates that this project is not
expected to impact any threatened or endangered species. If the status of threatened or
endangered species changes, or other species in the project area become listed as threatened or
endangered, then another consultation must be requested.
F.1.8 NOAA/National Marine Fisheries Service
No marine species listed as threatened or endangered use the project area. A biological
assessment must be performed to determine if any essential fish habitat will be impacted by the
project.
F.1.9 U.S. Coast Guard
As‐built drawings showing underwater cable locations must be provided to the U.S. Coast
Guard for incorporation into navigational charts.
F.1.10 U.S. Department of Energy (DOE)
Two additional permits are required from the DOE for sale of energy to markets in Canada.
These are:
1. Presidential Permit.
2. Export Authorization.
Projects that were built for the Canadian market would also require FERC licensing due to their
location on Federal land. These permit applications would be filed concurrently with submittal
of the License Application to the FERC. The development cost estimates and schedules include
these permitting processes for projects over 5 MW that could sell to Canadian markets.
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F.2 STATE OF ALASKA PERMITS
F.2.1 Alaska Department of Natural Resources
Coastal Zone Consistency Review: Although the Alaska Coastal Zone Management Program
was discontinued in 2010, there is a move to reconstitute it. Progress on this movement should
be followed. Likely much of the information for a possible future consistency review will be
gathered for other permitting agencies.
Land Authorizations: This project will not occupy State land.
Tidelands Permits: Tidelands easements will be required if undersea cables are to be used for
this project.
Material Sale Agreement: Not applicable.
Water Use Permits/Water Rights: Water rights from the Alaska Department of Natural
Resources will need to be obtained for this project.
F.2.2 Alaska Department of Fish and Game
The project will need to obtain either a fish habitat permit or a finding that a permit is not
required from the Alaska Department of Fish and Game.
F.2.3 Alaska Department of Transportation and Public Facilities
Not applicable.
F.2.4 Alaska Department of Environmental Conservation
Wastewater or Potable Water Permits: Not applicable.
Solid Waste Disposal Permit: Not applicable.
Air Quality Permit and Bulk Fuel Permits: Not applicable.
F.2.5 Regulatory Commission of Alaska
The Regulatory Commission of Alaska (RCA) governs how an electric utility may operate and
sell its power. The regulations are complex, and may be waived at the discretion of the five
RCA commissioners if they feel it is in the “Public Interest.” In general, the RCA regulations of
relevance to this project are as follows:
If a power producer produces less than 1 MW above its own power needs, it may sell
that excess power to a local utility without certification, and the utility must pay at its
“avoided cost” (for APC, that is currently about 28 cents per kWh). If the excess
produced is above 1 MW, the power producer must certify as an Independent Power
Producer, and must negotiate with the utility to sell that power to the utility.
An Independent Power Producer can either sell up to $50,000 worth of power, or to less
than 10 customers without being certified as a utility.
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A power producer can file as a utility within another utility’s service area, but it will be
up to RCA commissioners whether the producer gets that certificate or not.
A power producer may sell power to businesses owned in common with the owner of
the power producer without being certified as a utility.
A power producer can get a “service” contract with a utility to sell power to customers
using its transmission lines and equipment. In this case, the power producer will likely
pay a charge per kWh (wheeling charge) to the utility for the use of its transmission and
distribution infrastructure.
A power producer may sell power to a cooperative such as IPEC without being certified
as a utility.
In addition, a power producer can be exempted from having to be certified as a utility through
AS 42.05.711(r) as follows:
A plant or facility that generates electricity entirely from renewable energy resources, as that
term is defined in AS 42.45.045 , is exempt from regulation under this chapter if
(1) the plant or facility
(A) is first placed into commercial operation on or after the effective date of this
subsection and before January 1, 2016; and
(B) does not generate more than 65 megawatts of electricity;
(2) the electricity generated by the plant or facility is sold only to one or more electric
utilities that are regulated by the commission; and
(3) the person that constructs, owns, acquires, or operates the plant or facility has not
received from the State
(A) a grant that was used to generate the electricity from the renewable energy
resources; or
(B) a tax credit related to the generation of electricity from the renewable energy.
Exemption from economic regulation is also possible on public interest grounds under AS
42.05.711 (r).
F.3 LOCAL PERMITS
The project is located within the Municipality of Skagway, and is in an area zoned Residential‐
conservation. Electric facilities is a permitted principal use in this zoning area, however, a local
building permit will be required prior to construction.
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APPENDIX G –TECHNICAL ANALYSIS
G.1: Potential Project Configurations pages G‐1 to G‐7
G.2: Electrical Output of
Project Configurations pages G‐8 to G‐9
G.3: Transmission Alternatives pages G‐10 to G‐12
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G.1 POTENTIAL PROJECT CONFIGURATIONS
Hydropower development options for Burro Creek were identified by collecting and analyzing
resource data for Burro Creek. The resource data included stream hydrology, site topography,
and related information. Environmental and regulatory factors were also considered in
developing candidate project configurations.
Several potential diversion sites, powerhouse sites, and design flows were evaluated for Burro
Creek. These are summarized in Table G‐1 and discussed in this section. Each combination of
these project configurations was analyzed for estimated cost, estimated energy generation, and
environmental issues, and the most favorable project configurations identified.
Table G‐1: Range of Project Options Considered
Parameter Values Considered
Diversion Location
1. 1,160 ft. elevation
2. 1,000 ft. elevation
3. 800 ft. elevation
4. Existing Diversion (235 ft.)
5. Property Line (340 ft.)
Powerhouse Location
A. Existing Powerhouse (33 ft.)
B. Below Falls (50 ft.)
C. Above Falls (80 ft.)
D. North of Dock (50 ft.)
Design Flow
50 cfs (30‐inch penstock)
70 cfs (36‐inch penstock)
110 cfs (42‐inch penstock)
Source: Polarconsult Alaska, Inc., 2011.
G.1.1 Diversion Locations
Five diversion sites were considered in this study. As the diversion site moves upstream, the
project head increases, increasing potential energy output, but the available water in Burro
Creek decreases, decreasing potential energy output.
The diversion sites extend from the existing hydro intake at mile 0.42 (elevation 235 feet)
upstream to mile 2.58, where a major tributary joins Burro Creek from the south (elevation 1,160
feet). This tributary and another tributary that joins Burro Creek from the north at mile 2.74
comprise a significant fraction of the basin area, so a diversion above mile 2.58 is not considered
practical due to the reduced flow above these tributaries. Characteristics of the five diversion
locations considered are summarized in Table G‐2.
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Table G‐2: Diversion Site Considerations
Diversion
Site Elevation Basin Area
(Square Miles) Advantages Disadvantages
Site #5
Existing
Intake
235’ 12.33
‐ Exposed rock across creek
section.
‐ On private property, avoids
FERC licensing.
‐ Low head, limited
generation potential .
Site #4
Property
Line
340’ 12.21
‐ On private property, avoids
FERC licensing.
‐ 95’ more head.
‐ Lacks exposed bedrock,
more difficult construction.
Site #3
Conceptual 800’ 10.44 ‐ 460’ more head.
‐ Lacks exposed bedrock,
more difficult construction.
‐ On Federal property,
requires FERC licensing.
‐ 5,100’ more penstock and
access trail required
‐ 14.5% less water (gross).
Site #2
Conceptual 1,000’ 9.70 ‐ 200’ more head.
‐ Lacks exposed bedrock,
more difficult construction.
‐ On Federal property,
requires FERC licensing.
‐ 2,700’ more penstock and
access trail required.
‐ 7.1% less water (gross).
Site #1
Conceptual 1,160’ 9.10 ‐ 160’ more head.
‐ Lacks exposed bedrock,
more difficult construction.
‐ On Federal property,
requires FERC licensing.
‐ 2,200’ more penstock and
access trail required.
‐ 6.4% less water (gross).
Source: Polarconsult Alaska, Inc., 2011.
Diversion Site #5 – Existing Diversion (235 feet)
The existing diversion site (Photographs B‐4 through B‐6) is favorable due to the presence of
exposed bedrock that simplifies construction of a diversion structure. Topography at the site
also allows for the penstock to rapidly depart the creek bed, reducing flood hazard to the
penstock. A project developed at this site would also be wholly sited on private land,
simplifying the permitting requirements for the project. The primary disadvantage of this site is
that it is at a significantly lower elevation than upstream sites, limiting the energy potential of a
hydro project with a diversion sited here.
Existing access to the existing diversion site is via foot trail. The existing diversion was built
with hand labor, and no motorized trail exists. A construction trail could be built to this
diversion site using conventional methods and equipment. The most favorable route appears to
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start at the trail that heads north from the dock, and joins up with the existing penstock at
approximately station 5+25. The trail would deviate north from the existing penstock
paralleling it on a higher bench approximately 100 feet to the north and rejoining at the
diversion site.
Penstock routes would depend on the powerhouse location, and are shown on Figure A‐3.
Diversion Site #4 – Diversion at Property Line (340 feet)
A diversion at the property line was considered because it represents the maximum head that
can be developed on USS 1560. A diversion here would maximize energy generation while
avoiding the additional permits required to access Federal land.
Bedrock is not visible in the creek bed or surrounding terrain at this diversion site. In this area,
the creek is incised about six to eight feet into a relatively flat valley floor. Because of the coarse
bed material and lack of visible bedrock, the diversion structure should be kept as short as
possible to minimize the amount of water that flows through the gravels beneath the structure.
There is no development on USS 1560 above the existing diversion structure. The terrain from
the existing diversion up to the property line is not difficult for trail building. Approximately
250 feet of sidehill would be necessary approximately 400 feet below the diversion to maintain a
downhill grade from the diversion. The access trail could take an alternate route up this hill if
necessary. Field inspection also identified some possible small wetland areas along this route.
It may be practical to avoid these by proper routing of the access trail / penstock.
Diversion Site #3 – at 800‐foot Elevation
Field investigations on the ground for this study extended up to approximately the 700‐foot
elevation. The creek at the 800‐foot elevation was not inspected on the ground during field
investigations for this study. Based upon review of aerial photography and topographic maps,
conditions at 800 feet appear similar to conditions at and below 700 feet, with the creek incised 5
to 10 feet in a bed armored with large boulders. Little if any bedrock is exposed in the creek
bed. The primary advantage of this site is the increased elevation and increased generation
potential. Disadvantages include:
The project would be located on Federal land, requiring additional permits;
An additional 5,100 feet of access trails and penstock are required to capture the
additional 460 feet of head compared with an intake at 340 feet; and
The available flows in Burro Creek are reduced due to the loss of tributary flow,
decreasing potential project output.
The net effect of the differences between the 340 and 800‐foot diversion sites is positive. An
intake at 800 feet will generate more energy at a lower cost than an intake at 340 feet.
Access routes to the 800 foot diversion were not evaluated on the ground. Review of
topographic maps and aerial photographs suggest the terrain steepens and exposed bedrock
becomes more prevalent. Cost estimates assume more expensive trail work for blasting and
sidehill work to pioneer a trail to this site.
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Diversion Site #2 – Diversion at 1,000‐foot Elevation
Field investigations on the ground for this study extended up to approximately the 700‐foot
elevation. The creek at the 1,000‐foot elevation was not inspected on the ground during field
investigations for this study. Based upon review of aerial photography and topographic maps,
conditions at 1,000 feet appear similar to conditions along the creek from approximately 250 feet
to 700 feet. The primary advantage of this site is the increased elevation and increased
generation potential. Disadvantages include:
The project would be located on Federal land, requiring additional permits;
An additional 2,700 feet of access trails and penstock are required to capture the
additional 200 feet of head compared with an intake at 800 feet; and
The available flows in Burro Creek are reduced due to the loss of tributary flow,
decreasing potential project output.
The net effect of the differences between the 800‐foot and 1,000‐foot diversion sites, within the
level of detail of this study, is neutral. This project would output more energy than a project
with a diversion at 800 feet, but the estimated cost of energy from either project is
approximately equal.
Access routes to the 1,000‐foot diversion were not evaluated on the ground. Review of
topographic maps and aerial photographs suggest that the terrain between the 800 and 1,000‐
foot diversions is similar to terrain in the vicinity of the 340‐foot diversion site. Cost estimates
reflect these assumed conditions.
Diversion Site #1 – Diversion at 1,160‐foot Elevation
A diversion at 1,160‐foot elevation would be located just downstream of a major tributary. This
is the farthest upstream diversion location that is considered practical. Field investigations on
the ground for this study extended up to approximately the 700‐foot elevation. The creek at the
1,160‐foot elevation was not inspected on the ground during field investigations for this study.
Based upon review of aerial photography and topographic maps, conditions at 1,000 feet appear
similar to conditions along the creek from approximately 250 to 700‐foot elevations. The
primary advantage of this site is the increased elevation and increased generation potential.
Disadvantages include:
The project would be located on Federal land are require additional permits;
An additional 2,200 feet of access trails and penstock are required to capture the
additional 160 feet of head compared with an intake at 1,000 feet; and
The available flows in Burro Creek are reduced due to the loss of tributary flow,
decreasing potential project output.
The net effect of the differences between the 1,000‐foot and 1,160‐foot diversion sites, within the
level of detail of this study, is negative. The additional project costs are not justified by the
additional energy output.
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Access routes to the 1,160‐foot diversion were not evaluated on the ground. Review of
topographic maps and aerial photographs suggest that the terrain between the 1,000 and 1,160‐
foot diversions is similar to terrain in the vicinity of the 340‐foot diversion site. Cost estimates
reflect these assumed conditions.
G.1.2 Penstock Routes
Upper Penstock Routes
Upper penstock routes are shown on Figure A‐4. Penstocks starting at diversion sites 1, 2, or 3
would initially be built on access trails that side hill through mountainous terrain with typical
slopes of 2:1 to 3:1. These access trails would be built at a 2 to 4% grade descending from the
diversion site. Some blasting will likely be necessary to maintain this grade. Steeper grades are
allowable to avoid prominent outcrops or other obstacles, but maintaining a shallow grade will
allow for increased use of lower pressure pipe, reducing penstock material costs.
Approximately 1,000 feet downstream of diversion site 3, all three penstock routes encounter
steeper terrain. For the next approximately 3,500’, the penstock routes traverse terrain with
typical slopes of 1:1. Significant trail building work and blasting will be needed to provide
access and a penstock bench through this area.
An incised ravine occurs approximately 1,500 feet below diversion site 3. This ravine is co‐
located with a major avalanche chute on the south side of Burro Creek. There is abundant
evidence that powder blast from this avalanche chute has felled mature trees approximately
200‐300 vertical feet up the north side of Burro Creek Valley. The penstock from diversion site 3
(800‐foot elevation) would cross through this hazard zone. Penstocks from diversion sites 1
and 2 would pass above this hazard zone.
All three penstock routes would start a steep (20 to 25%) downhill grade towards the
powerhouse near the northwest property corner of USS 1560. As the penstock routes approach
the existing intake site, they would follow similar routes to the lower project penstock routes
shown on Figure A‐3 to reach any of the four proposed powerhouse sites. Figure A‐4 only
shows routes to powerhouse site ‘D’ for clarity.
Lower Penstock Routes
Lower penstock routes are shown on Figure A‐3. Penstocks starting at diversion sites 4 would
initially cross relatively flat terrain. About 250 feet from the diversion, the penstock would start
to sidehill through 1:1 slopes for about 400 feet. After this sidehill, the penstock would traverse
another 800 feet of relatively flat terrain until it reached the vicinity of the existing intake
structure. At this point, the penstock route would diverge as shown on Figure A‐3 depending
on the powerhouse site. Above the existing intake /diversion site 5, there is sufficient material
on‐site to build trails and bed the penstock. Below the existing intake /diversion site 5, exposed
rock becomes increasingly common.
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G.1.3 Powerhouse Locations
Four potential powerhouse sites were considered in this study. They are listed in Table G‐3 and
shown in Figure A‐2. Advantages and disadvantages of the powerhouse sites are summarized
in Table G‐3. Analysis of potential project configurations considered all of these sites.
Table G‐3: Powerhouse Site Considerations
Powerhouse
Site Elevation Advantages Disadvantages
Site ‘A’
Existing Site 33’
‐ Highest head of sites.
‐ returns all water to Burro Creek.
‐ Good access.
‐ In center of existing development.
Could be incompatible with future
development (noise, aesthetics)
‐ Reduced flow in part of fish habitat.
Site ‘B’
Below Falls 50’
‐ Returns all water to Burro Creek
near top of fish habitat.
‐ Good access.
‐ On edge of existing development.
Could be incompatible with future
developments.
‐ Reduced flow in part of fish habitat
Site ‘C’
Above Falls 80’
‐ Returns all water to Burro Creek
above fish habitat.
‐ Avoids aesthetic impacts to
waterfall.
‐ Lowest head of all sites.
‐ May impact waterfall viewshed
from some vantages.
‐ Access not as good as other sites.
Site ‘D’
North of
Dock
50’
‐ Away from existing development
(avoids noise or aesthetic impacts).
‐ Good access.
‐ Tailrace discharges to Lynn Canal,
reduces flows in Burro Creek fish
habitat.
Source: Polarconsult Alaska, Inc., 2011.
For projects with diversions at 235 feet or 340 feet, the elevation of the powerhouse site
significantly influences the energy output of the project. For projects with diversions at 800 feet
or above, the elevation of the powerhouse site becomes of lesser importance. Because of this,
evaluation of the lower head projects includes individual powerhouse sites, but evaluation of
the higher head projects assumes the existing powerhouse site in all cases. The higher head
projects could use any of the four powerhouse sites with a less than 5% variation in cost or
project energy output.
G.1.4 Design Flows
Design flows of 50, 70, and 110 cfs were considered in this study. Table G‐4 summarizes the
expected plant capacity factor for each design flow.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report G‐7
Table G‐4: Expected Plant Capacity Factor for Different Project Configurations
Design
Flow
(cfs)
Nominal
Penstock
Diameter
Diversion Site 5
(235 ft., Existing
Diversion)
Diversion Site 4
(340 ft., Property
Line)
Diversion
Site 3
(800 ft.)
Diversion
Site 2
(1,000 ft.)
Diversion
Site 1
(1,160 ft.)
50 30‐inch 54.0% 52.9% 50.5% 49.2% 48.2%
70 36‐inch 47.8% 46.9% 44.2% 42.8% 41.6%
110 42‐inch 39.5% 38.1% 34.9% 33.4% 32.4%
Source: Polarconsult Alaska, Inc., 2011.
Notes:
Plant capacity factor includes an assumed 90% plant reliability applied to net energy generation. All capacity factors
are for projects with powerhouses sited at the existing powerhouse site.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report G‐8
G.2 ELECTRICAL OUTPUT OF PROJECT CONFIGURATIONS
The five diversion locations, four powerhouse sites, and three design flows create a total of 60
potential project configurations. This number was reduced to 33 configurations by eliminating
consideration of the multiple powerhouse sites for the three highest‐head diversion options.
For projects with diversions at 235 feet (existing diversion) or 340 feet (property line), the
elevation and location of the powerhouse site significantly influences the estimated cost and
estimated energy output of the project. For projects with diversions at 800 feet and above,
differences in the powerhouse elevation and location is of lesser importance, and is estimated to
vary cost and energy output by less than 5%. At this stage of analysis, this difference is not
meaningful. If one of the higher head projects is selected for development, powerhouse siting
should receive scrutiny with regard to energy output, cost, environmental factors, and
aesthetics.
Average energy output was calculated for each of the 33 configurations. Average daily flow
statistics from the Burro Creek hydrology model (Appendix C) were input to an engineering
model for each of the project configurations to estimate average daily energy generation. The
engineering model computed net energy generation considering the following factors:
Gross project head
Penstock friction losses and net head
Daily project flow
Turbine type and turbine efficiency curve 9
Station service power loads
Transformer and cable losses from Burro Creek to delivery in Skagway.
Table G‐5 presents the results of this analysis on a monthly and annual basis.
The estimated performance data presented in Table G‐5 was reviewed in conjunction with
estimated capital and annualized project costs to identify the project configurations expected to
produce the lowest cost power. The results of this analysis are presented in Appendix H.
9 A single two‐jet Pelton turbine is assumed for all project configurations. Turbine efficiency curves
vary with the project installed capacity in accordance with typical turbine manufacturer’s data.
Burro Creek Holdings, LLC Burro Creek Hydroelectric Study Polarconsult Alaska, Inc. November 2011 – Final Report G‐9 Table G‐5: Average Monthly and Annual Energy Generation of Project Configurations Project Configuration Installed Capacity (kW) January (kWh) February (kWh) March (kWh) April (kWh) May (kWh) June (kWh) July (kWh) August (kWh) September (kWh) October (kWh) November (kWh) December (kWh) ANNUAL (kWh) SEASONAL (4/1 – 9/30) (kWh) Seasonal / Annual 50 cfs Design Flow (30” penstock) kWh net generation per month 1D‐50 3,400 245,000 225,000 196,000 500,000 1,964,000 2,206,000 2,273,000 2,145,000 1,813,000 1,840,000 737,000 456,000 14,600,000 10,901,000 75% 2D‐50 3,000 225,000 207,000 183,000 461,000 1,721,000 1,904,000 1,964,000 1,877,000 1,609,000 1,626,000 675,000 421,000 12,873,000 9,536,000 74% 3D‐50 2,400 194,000 179,000 160,000 392,000 1,402,000 1,522,000 1,571,000 1,520,000 1,321,000 1,329,000 577,000 359,000 10,526,000 7,728,000 73% 4A‐50 820 80,000 74,000 65,000 155,000 498,000 521,000 539,000 531,000 474,000 478,000 231,000 144,000 3,790,000 2,718,000 72% 4B‐50 900 87,000 81,000 72,000 170,000 543,000 568,000 587,000 578,000 517,000 521,000 252,000 157,000 4,133,000 2,963,000 72% 4C‐50 900 87,000 81,000 72,000 170,000 548,000 574,000 593,000 585,000 521,000 526,000 253,000 158,000 4,168,000 2,991,000 72% 4D‐50 970 93,000 86,000 76,000 181,000 587,000 616,000 637,000 628,000 559,000 563,000 269,000 167,000 4,462,000 3,208,000 72% 5A‐50 430 46,000 43,000 36,000 89,000 264,000 273,000 282,000 280,000 252,000 255,000 135,000 86,000 2,041,000 1,440,000 71% 5B‐50 490 54,000 50,000 41,000 103,000 303,000 313,000 324,000 322,000 289,000 293,000 156,000 99,000 2,347,000 1,654,000 70% 5C‐50 500 54,000 50,000 41,000 104,000 309,000 321,000 331,000 329,000 295,000 298,000 156,000 99,000 2,387,000 1,689,000 71% 5D‐50 560 59,000 55,000 45,000 114,000 345,000 359,000 371,000 368,000 329,000 332,000 172,000 109,000 2,658,000 1,886,000 71% 70 cfs Design Flow (36” penstock) kWh net generation per month 1D‐70 4,400 214,000 196,000 168,000 498,000 2,455,000 3,130,000 3,146,000 2,627,000 2,125,000 2,178,000 764,000 442,000 17,943,000 13,981,000 78% 2D‐70 3,800 200,000 186,000 155,000 459,000 2,183,000 2,702,000 2,738,000 2,350,000 1,908,000 1,950,000 696,000 408,000 15,935,000 12,340,000 77% 3D‐70 3,000 179,000 167,000 139,000 392,000 1,791,000 2,160,000 2,202,000 1,946,000 1,583,000 1,624,000 591,000 353,000 13,127,000 10,074,000 77% 4A‐70 1,030 77,000 71,000 60,000 158,000 649,000 742,000 763,000 710,000 591,000 603,000 235,000 143,000 4,802,000 3,613,000 75% 4B‐70 1,100 84,000 77,000 65,000 173,000 708,000 808,000 832,000 775,000 645,000 659,000 257,000 157,000 5,240,000 3,941,000 75% 4C‐70 1,150 84,000 77,000 65,000 173,000 713,000 816,000 839,000 781,000 649,000 663,000 257,000 157,000 5,274,000 3,971,000 75% 4D‐70 1,220 89,000 82,000 69,000 184,000 762,000 874,000 900,000 835,000 693,000 707,000 273,000 167,000 5,635,000 4,248,000 75% 5A‐70 630 40,000 36,000 30,000 91,000 347,000 389,000 401,000 378,000 317,000 324,000 140,000 85,000 2,578,000 1,923,000 75% 5B‐70 720 46,000 42,000 34,000 105,000 399,000 446,000 460,000 434,000 365,000 373,000 162,000 98,000 2,964,000 2,209,000 75% 5C‐70 735 46,000 42,000 34,000 105,000 405,000 455,000 469,000 442,000 370,000 377,000 163,000 98,000 3,006,000 2,246,000 75% 5D‐70 800 50,000 46,000 38,000 116,000 449,000 507,000 523,000 491,000 410,000 418,000 179,000 107,000 3,334,000 2,496,000 75% 110 cfs Design Flow (42” penstock) kWh net generation per month 1D‐110 7,300 193,000 183,000 80,000 460,000 2,733,000 4,371,000 4,175,000 2,798,000 2,135,000 2,281,000 773,000 399,000 20,581,000 16,672,000 81% 2D‐110 6,500 182,000 168,000 88,000 431,000 2,516,000 3,904,000 3,739,000 2,584,000 1,998,000 2,102,000 711,000 375,000 18,798,000 15,172,000 81% 3D‐110 5,250 156,000 143,000 108,000 376,000 2,143,000 3,217,000 3,097,000 2,202,000 1,712,000 1,816,000 612,000 333,000 15,915,000 12,747,000 80% 4A‐110 1,840 64,000 59,000 52,000 154,000 834,000 1,151,000 1,130,000 870,000 693,000 719,000 245,000 137,000 6,108,000 4,832,000 79% 4B‐110 2,000 70,000 65,000 57,000 168,000 911,000 1,255,000 1,233,000 950,000 758,000 786,000 268,000 150,000 6,671,000 5,275,000 79% 4C‐110 2,025 70,000 65,000 57,000 168,000 915,000 1,265,000 1,242,000 955,000 760,000 789,000 268,000 150,000 6,704,000 5,305,000 79% 4D‐110 2,170 74,000 69,000 61,000 178,000 975,000 1,354,000 1,329,000 1,017,000 809,000 840,000 285,000 160,000 7,151,000 5,662,000 79% 5A‐110 970 31,000 29,000 25,000 86,000 455,000 609,000 600,000 472,000 384,000 400,000 145,000 74,000 3,310,000 2,606,000 79% 5B‐110 1,100 36,000 33,000 29,000 99,000 525,000 700,000 690,000 544,000 443,000 462,000 167,000 86,000 3,814,000 3,001,000 79% 5C‐110 1,130 36,000 33,000 29,000 100,000 530,000 712,000 701,000 549,000 446,000 465,000 168,000 86,000 3,855,000 3,038,000 79% 5D‐110 1,250 39,000 37,000 32,000 109,000 585,000 793,000 780,000 606,000 492,000 513,000 184,000 94,000 4,264,000 3,365,000 79% Project Configurations: 1 = 1,160’ Diversion, 2 = 1,000’ Diversion, 3 = 800’ Diversion, 4 = 340’ Diversion (Diversion at USS 1560 property line), 5 = 235’ Diversion (existing hydro diversion). A = powerhouse above waterfall at 80’, B = powerhouse below waterfall at 50’, C = powerhouse north of dock at 50’, D = powerhouse at existing powerhouse site at 33’. For projects with diversions at 800’ and above (sites 1, 2, and 3), the powerhouse location has a minor effect on energy location, so only the existing powerhouse site (‘D’) is listed. Table G‐5: Average Monthly and Annual Energy Generation of Different Project Configurations
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report G‐10
G.3 TRANSMISSION ALTERNATIVES
Four options were considered to move the electricity generated at Burro Creek to market.
1. AC submarine cable from Burro Creek to Skagway.
2. AC submarine cable from Burro Creek to Kasidaya Creek.
3. DC submarine cable from Burro Creek to Skaway.
4. AC overland transmission line from Burro Creek to Dyea and on to Skagway.
Figure A‐5 shows these four routing options. Of these options, an AC submarine cable from
Burro Creek to Skagway is estimated to be the least costly, and is the transmission method used
in this study to get Burro Creek power to market. These four transmission options are
discussed below, and estimated costs for each option are summarized in Table G‐6.
Table G‐6: Estimated Costs for Power Line – Burro Creek to Skagway
Item
AC Cable
to
Skagway
AC Cable to
Kasidaya
Creek
HVDC
Cable to
Skagway
Overland
AC to
Skagway
Pre‐construction (Permitting, Design) $135,000 $135,000 $135,000 $175,000
Interconnections, Burro and Skagway $30,000 $30,000 $1,900,000 $20,000
AC Submarine Cable $1,200,000 $1,500,000 ‐ ‐
DC Submarine Cable ‐ ‐ $800,000 ‐
AC Overhead Power Line ‐ ‐ ‐ $615,000
AC Overhead Power Line (Upgrade to 3 ph) ‐ ‐ ‐ $245,000
AC Buried Power Line ‐ ‐ ‐ $345,000
AC Buried Power Line (Upgrade to 3 ph) ‐ ‐ ‐ $540,000
Construction Management & Administration $110,000 $130,000 $220,000 $150,000
Construction Engineering & Inspection $110,000 $130,000 $220,000 $150,000
Contingency (25%) $340,000 $415,000 $680,000 $470,000
Total Estimated Cost $1,925,000 $2,340,000 $3,955,000 $2,710,000
Source: Polarconsult Alaska, Inc., 2011.
Note: All cost estimates are for a 3 MW project and transmission line capacity.
G.3.1 AC Submarine Cable from Burro Creek to Skagway
An AC cable from Burro Creek to Skagway would be approximately 2.2 miles long and could
be routed to stay in waters less than 600 feet deep. Bottom profiles along the cable route were
obtained from NOAA navigation charts and bathymetric surveys performed for installation of
APC’s Upper Lynn Canal transmission system. For reliability, four individual power cables
would be installed, three cables for three phase service and one spare cable.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report G‐11
G.3.2 AC Submarine Cable from Burro Creek to Kasidaya Creek
AP&T’s upper Lynn Canal transmission system makes a shore landing at the Kasidaya Creek
hydroelectric project. An AC submarine cable from Burro Creek to Kasidaya Creek is feasible,
however it would be approximately ¾ of a mile longer and cross deeper waters than a similar
cable to Skagway. For these reasons, the cost of this cable connection is expected to be slightly
higher than a submarine cable to Skagway. This route may warrant future consideration if a
cable to Skagway is determined to not be feasible.
G.3.3 HVDC Submarine Cable from Burro Creek to Skagway
In the past, High Voltage Direct Current (HVDC) transmission has not been an option for
power transmission needs under approximately 50 MW. Starting in 2007, the Denali
Commission began funding development of small‐scale HVDC transmission system technology
in order to lower the costs of small transmission lines in Alaska. The first full‐functionality 500
kW HVDC converters will be built and tested by the end of 2011, and these converters are
expected to be commercially available by the time Burro Creek is under final design. HVDC
interties have higher terminal costs than AC interties, but lower per‐mile costs. Thus, HVDC
interties are generally not cost effective for interties as short as the Burro Creek – Skagway
intertie needed for this project. The HVDC technology was reviewed in this application to see if
it presents a more economic alternative to AC cables.
The HVDC converters would feed directly from the 480 volt bus of the Burro Creek power
plant. Under the larger project configurations, a step down transformer from 4,160 volt
generation to 480 volt for DC conversion would be required. From the converters, two HVDC
submarine cables would cross 2.2 miles to Skagway to an identical set of HVDC converters.10 A
step‐up transformer would convert the 480 volt three phase from the HVDC converters up to
the local distribution voltage on the APC grid. One submarine cable would operate at +50 kV
DC, and the second cable would be a neutral metallic return. Sea electrodes would also be
provided at each end of the HVDC line for emergency operation in sea‐return mode in the event
of a cable failure.
G.3.4 AC Overland transmission line from Burro Creek to Dyea and on to Skagway
This transmission routing would consist of the following major parts:
Approximately 3.5 miles of new overhead 24.9 kV three phase AC power line from
Burro Creek north along Lynn Canal towards Dyea.
10 In rural settings, HVDC can use a single cable with sea return to complete the transmission circuit.
At this stage of analysis for this application, a metallic return cable is assumed to avoid induced
currents and accelerated corrosion of the extensive marine infrastructure in Skagway. Further
investigation may demonstrate that a sea return for an HVDC transmission link is an appropriate
system configuration for this project. However, for this project, the estimated cost of an HVDC
transmission link is not competitive against AC even using a single cable / sea return configuration
because the transmission line is so short.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report G‐12
Approximately 2.3 miles of buried 24.9 kV three phase AC power line within Klondike
Gold Rush National Historic Park to reach the end of APC’s existing single phase buried
distribution in Dyea.
Approximately 2.7 miles of upgrade of single phase buried power line to three phase
24.9 kV buried power line from Dyea towards Skagway.
Approximately 2.7 miles of upgrade of single phase overhead power line to three phase
overhead 24.9 kV power line to the end of existing three phase distribution near
Skagway.
In total, approximately 11.2 miles of new or upgraded overland power line is necessary to reach
the Skagway market. The length and cost of line extensions / upgrades is not competitive with
more direct submarine cable options. Additionally, the overland power line route would
traverse very steep terrain between Burro Creek and Dyea that is prone to avalanches and
logistically challenging. Aesthetics of this power line are also a concern, as the power line
would be highly visible from the Skagway waterfront as well as from cruise ships arriving in
Skagway.
Another factor is that this line routing would require use of Federal lands, requiring FERC
involvement, regardless of whether the hydro project used lands upstream from USS 1560.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report
APPENDIX H – CAPITAL COST ESTIMATES AND FINANCIAL
SCENARIOS
H.1: Project Cost Estimates pages H‐1 to H‐7
H.2: Assumptions in Project Cost Estimates and Scenarios
pages H‐6 to H‐8
H.3: Funding Opportunities page H‐9
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report H‐1
H.1 PROJECT COST ESTIMATES
The total installed cost of select project configurations is presented in Table H‐1.
Table H‐2 presents simplified business models for select project configurations. Two financing
structures and two market structures are considered, for a total of four Business Model
Scenarios. These are:
Business Model Scenarios
Presented in Table H‐2
Energy Market
Full Energy
Sales
Partial Energy
Sales
Financing
Structure
20% Debt, Balance Equity MODEL 1 MODEL 2
50% Grants, Balance Equity and Debt MODEL 3 MODEL 4
The first of the two financing structures assumes no grants are used to pay for the project’s
capital costs, so the project is financed through a combination of 20% equity and 80% debt.
The second of the three financing structures assumes that grants are used for 50% of the
project’s capital costs, up to a maximum of $8,500,000. 11 The balance of the capital cost is
assumed to come from owner equity (up to 20% of the total capital cost), and any remaining
balance is provided as debt.
Many other financing structures are possible, but these two cases reasonably consider the
resultant annualized project expenses and resulting energy sales price.
Two markets are considered. The first is full energy sales, so the full potential output of the
project is sold to a buyer. This might be the Palmer Mine or Yukon Energy connection, for
example. The second market is for partial energy sales. This might include sales to IPEC, sales
to commonly held businesses, and late winter sales to APC, as well as sales to cruise ships
docked in Skagway. The annual energy sales under this option are calculated as the full output
from April 1st through September 30th, but the timing of these sales could occur throughout the
year.
For each scenario, annual debt service, operating expenses, return on equity, and operating
margins are estimated. The sum of these values is then divided by the estimated average
annual net energy sales to arrive at the estimated energy sales price needed for that project
configuration and business model scenario.
There are numerous assumptions implicit in the numbers presented in Tables H‐1 and H‐2.
These are discussed in Section H.2.
11 $8,500,000 in grants could come in the form of an $8,000,000 grant from the state’s Renewable Energy
Grant Program, and a $500,000 grant from the USDA Rural Development Grant Program. It is not
known if these grant programs will still exist, operate under their existing rules, or be funded when
Burro Creek is ready to apply for construction grants. Other grant opportunities are discussed in
Section H.3.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report H‐2
While configuration 3D‐70 has the lowest estimated energy sales price at full sales, there are
several other project configurations with estimated energy sales prices within 0.5 cents of the
price for this configuration. At the level of analysis conducted in this study, these differences
are not significant. As the market for power from Burro Creek becomes better defined and
Burro Creek receives further scrutiny and analysis, these estimates can be refined and reviewed
with regard to the demand for power to determine the optimal project capacity and
configuration at Burro Creek.
Burro Creek Holdings, LLC Burro Creek Hydroelectric Study Polarconsult Alaska, Inc. November 2011 – Final Report H‐3 Table H‐1: Cost Estimates and Financial Analysis for Select Project Configurations PROJECT CONFIGURATIONS 50 CFS DESIGN FLOW 70 CFS DESIGN FLOW110 CFS DESIGN FLOWPROJECT PARAMETERS 1D‐50 2D‐50 3D‐50 4D‐50 5D‐50 1D‐70 2D‐70 3D‐70 4D‐70 5D‐70 1D‐110 2D‐110 3D‐110 4D‐110 5D‐110 Plant Capacity Factor 48.2% 49.2% 50.3% 52.6% 53.8%41.6% 42.8% 44.2% 46.9% 47.8%32.4% 33.2% 34.6% 37.7% 38.7% Installed Capacity (kW) 3,400 3,000 2,400 970 5604,400 3,800 3,400 1,220 8007,300 6,500 5,250 2,170 1,250 Avg. Ann. Net Energy Output (MWh) 14,600 12,873 10,526 4,462 2,65817,943 15,935 13,127 5,635 3,33420,581 18,798 15,915 7,151 4,264 Avg. Seasonal Energy Output (MWh) 10,901 9,536 7,728 3,208 1,88613,981 12,340 10,074 4,248 2,49616,672 15,172 12,747 5,662 3,365 Seasonal Output as % of Annual 75% 74% 73% 72% 71%78% 77% 77% 75% 75%81% 81% 80% 79% 79% Penstock Length (feet) 12,600 10,300 7,600 2,700 1,30012,600 10,300 7,600 2,700 1,30012,600 10,300 7,600 2,700 1,300 Gross Head (feet) 1,130 970 770 310 2051,130 970 770 310 2051,130 970 770 310 205 DEVELOPMENT COSTS Pre‐construction (studies, permitting, design, etc.) $630,000 $625,000 $610,000 $310,000 $305,000$630,000 $625,000 $610,000 $310,000 $305,000$630,000 $625,000 $610,000 $310,000 $305,000 Transmission Line $1,214,000 $1,203,000 $1,190,000 $1,171,000 $1,208,000$1,247,000 $1,231,000 $1,212,000 $1,186,000 $1,221,000$1,310,000 $1,286,000 $1,256,000 $1,214,000 $1,251,000 Access Trails $2,165,000 $1,796,000 $1,118,000 $212,000 $124,000$2,316,000 $1,796,000 $1,118,000 $212,000 $124,000$2,560,000 $1,985,000 $1,521,000 $323,000 $159,000 Diversion / Intake $251,000 $225,000 $192,000 $192,000 $129,000$263,000 $236,000 $204,000 $204,000 $131,000$300,000 $273,000 $241,000 $241,000 $148,000 Penstock $2,772,000 $1,833,000 $1,470,000 $432,000 $192,000$3,542,000 $2,249,000 $1,727,000 $520,000 $227,000$4,300,000 $2,689,000 $2,065,000 $616,000 $273,000 Powerhouse $2,214,000 $1,972,000 $1,610,000 $968,000 $680,000$2,947,000 $2,605,000 $2,153,000 $1,123,000 $837,000$4,416,000 $3,831,000 $3,104,000 $1,485,000 $1,135,000 Construction Equipment $507,000 $491,000 $398,000 $272,000 $220,000$507,000 $491,000 $398,000 $272,000 $220,000$507,000 $491,000 $398,000 $398,000 $220,000 Shipping $317,000 $234,000 $190,000 $116,000 $98,000$438,000 $317,000 $251,000 $140,000 $111,000$625,000 $438,000 $339,000 $176,000 $130,000 Construction Engineering $533,000 $470,000 $381,000 $222,000 $183,000$559,000 $479,000 $389,000 $224,000 $185,000$606,000 $514,000 $443,000 $246,000 $196,000 Construction Management / Administration $944,000 $775,000 $617,000 $336,000 $265,000$1,126,000 $893,000 $706,000 $366,000 $287,000$1,402,000 $1,099,000 $892,000 $445,000 $332,000 Contractor Margin $800,000 $704,000 $571,000 $333,000 $275,000$839,000 $719,000 $584,000 $336,000 $278,000$909,000 $771,000 $665,000 $369,000 $294,000 Contingency $2,360,000 $1,938,000 $1,542,000 $841,000 $663,000$2,815,000 $2,231,000 $1,765,000 $914,000 $718,000$3,504,000 $2,748,000 $2,231,000 $1,113,000 $829,000 ESTIMATED TOTAL CAPITAL COST $14,707,000 $12,266,000 $9,889,000 $5,405,000 $4,342,000$17,229,000 $13,872,000 $11,117,000 $5,807,000 $4,644,000$21,069,000 $16,750,000 $13,765,000 $6,936,000 $5,272,000 1 = 1,160’ Diversion, 2 = 1,000’ Diversion, 3 = 800’ Diversion, 4 = 340’ Diversion (Diversion at USS 1560 property line), 5 = 235’ Diversion (existing hydro diversion); D = powerhouse at existing powerhouse site at 33’. Avg. (average) Seasonal Energy Output is from April 1 through September 30. Source: Polarconsult Alaska, Inc., 2011. Table H‐1: Cost Estimates and Financial Analysis for Select Project Configurations
Burro Creek Holdings, LLC Burro Creek Hydroelectric Study Polarconsult Alaska, Inc. November 2011 – Final Report H‐4 Table H‐2: Economic Cases for Select Project Configurations PROJECT CONFIGURATIONS 50 CFS DESIGN FLOW 70 CFS DESIGN FLOW110 CFS DESIGN FLOWFINANCING MODELS 1D‐50 2D‐50 3D‐50 4D‐50 5D‐50 1D‐70 2D‐70 3D‐70 4D‐70 5D‐70 1D‐110 2D‐110 3D‐110 4D‐110 5D‐110 EQUITY AND DEBT FINANCING MODELS (NO GRANTS) Owner Equity (20%) $2,961,000 $2,473,000 $1,998,000 $1,101,000 $888,000$3,466,000 $2,794,000 $2,243,000 $1,181,000 $949,000$4,234,000 $3,370,000 $2,773,000 $1,407,000 $1,074,000 Grants (Existing Only) $40,000 $40,000 $40,000 $40,000 $40,000$40,000 $40,000 $40,000 $40,000 $40,000$40,000 $40,000 $40,000 $40,000 $40,000 Debt (80%) $11,706,000 $9,753,000 $7,851,000 $4,264,000 $3,414,000$13,723,000 $11,038,000 $8,834,000 $4,586,000 $3,655,000$16,795,000 $13,340,000 $10,952,000 $5,489,000 $4,158,000 TOTAL PROJECT CAPITAL COST $14,707,000 $12,266,000 $9,889,000 $5,405,000$4,342,000$17,229,000$13,872,000$11,117,000$5,807,000$4,644,000$21,069,000 $16,750,000 $13,765,000$6,936,000$5,272,000 Debt Service $850,000 $709,000 $570,000 $310,000 $248,000$997,000 $802,000 $642,000 $333,000 $265,000$1,220,000 $969,000 $796,000 $399,000 $302,000 O, M, R, & R $226,000 $196,000 $159,000 $71,000 $45,000$276,000 $240,000 $196,000 $87,000 $54,000$322,000 $285,000 $240,000 $108,000 $68,000 Return on Equity & Operating Margin $888,000 $742,000 $600,000 $330,000 $267,000$1,040,000 $838,000 $673,000 $354,000 $285,000$1,270,000 $1,011,000 $832,000 $422,000 $322,000 ANNUALIZED COSTS $2,852,000 $2,389,000 $1,929,000 $1,041,000$827,000$3,353,000$2,718,000$2,184,000$1,128,000$889,000$4,082,000 $3,276,000 $2,700,000$1,351,000$1,014,000MODEL #1: EQUITY AND DEBT FINANCING WITH FULL SALES (NO GRANTS) Annual MWh Sold 14,600 12,873 10,526 4,462 2,65817,943 15,935 13,127 5,635 3,33420,581 18,798 15,915 7,151 4,264 REQUIRED POWER SALES RATE NO GRANT & PARTIAL SALES ($/kWh) $0.137 $0.130 $0.129 $0.162 $0.213$0.131 $0.120 $0.118 $0.140 $0.184$0.139 $0.123 $0.120 $0.133 $0.165 MODEL #2: EQUITY AND DEBT FINANCING WITH PARTIAL SALES (NO GRANTS) Annual MWh Sold 10,901 9,536 7,728 3,208 1,88613,981 12,340 10,074 4,248 2,49616,672 15,172 12,747 5,662 3,365 REQUIRED POWER SALES RATE NO GRANT & PARTIAL SALES ($/kWh) $0.180 $0.173 $0.172 $0.222 $0.297$0.165 $0.152 $0.150 $0.182 $0.242$0.169 $0.149 $0.146 $0.164 $0.206 50% GRANT, 20% EQUITY AND 30% DEBT FINANCING MODELS Owner Equity (20%) $2,961,000 $2,473,000 $1,998,000 $1,101,000 $888,000$3,466,000 $2,794,000 $2,243,000 $1,181,000 $949,000$4,234,000 $3,370,000 $2,773,000 $1,407,000 $1,074,000 Grants (80% up to $8,500,000 max.) $7,333,000 $6,113,000 $4,924,000 $2,683,000 $2,151,000$8,500,000 $6,916,000 $5,538,000 $2,883,000 $2,302,000$8,500,000 $8,355,000 $6,861,000 $3,448,000 $2,615,000 Debt (Remaining Balance) $4,413,000 $3,680,000 $2,967,000 $1,621,000 $1,303,000$5,263,000 $4,162,000 $3,336,000 $1,743,000 $1,393,000$8,335,000 $5,025,000 $4,131,000 $2,081,000 $1,583,000 TOTAL PROJECT CAPITAL COST $14,707,000 $12,266,000 $9,889,000 $5,405,000$4,342,000$17,229,000$13,872,000$11,117,000$5,807,000$4,644,000$21,069,000 $16,750,000 $13,765,000$6,936,000$5,272,000 Debt Service $321,000 $267,000 $216,000 $118,000 $95,000$382,000 $302,000 $242,000 $127,000 $101,000$606,000 $365,000 $300,000 $151,000 $115,000 O, M, R, & R $262,000 $228,000 $186,000 $82,000 $52,000$321,000 $280,000 $229,000 $101,000 $63,000$322,000 $285,000 $240,000 $108,000 $68,000 Return on Equity & Operating Margin $651,000 $544,000 $440,000 $242,000 $196,000$763,000 $614,000 $493,000 $260,000 $209,000$931,000 $741,000 $610,000 $310,000 $236,000 ANNUALIZED COSTS $1,885,000 $1,583,000 $1,282,000 $684,000$539,000$2,229,000$1,810,000$1,457,000$748,000$582,000$2,790,000 $2,132,000 $1,760,000$879,000$655,000MODEL #3: 50% GRANT, 20% EQUITY AND 30% DEBT FINANCING WITH FULL SALES Annual MWh Sold 14,600 12,873 10,526 4,462 2,65817,943 15,935 13,127 5,635 3,33420,581 18,798 15,915 7,151 4,264 REQUIRED POWER SALES RATE 50% GRANT & FULL SALES ($/kWh) $0.085 $0.081 $0.080 $0.099 $0.129$0.082 $0.075 $0.073 $0.086 $0.112$0.093 $0.077 $0.075 $0.083 $0.101 MODEL #4: 50% GRANT, 20% EQUITY AND 30% DEBT FINANCING WITH PARTIAL SALES Annual MWh Sold 10,901 9,536 7,728 3,208 1,88613,981 12,340 10,074 4,248 2,49616,672 15,172 12,747 5,662 3,365 REQUIRED POWER SALES RATE 50% GRANT & PARTIAL SALES ($/kWh) $0.110 $0.106 $0.105 $0.134 $0.178$0.102 $0.094 $0.093 $0.111 $0.146$0.111 $0.092 $0.090 $0.100 $0.125 See Section H.2 for assumptions used in these financial models. Source: Polarconsult Alaska, Inc., 2011. Note: Estimated required power sales rates in all scenarios in Table H‐2 is for delivery to Alaska Power Company in Skagway, and does not include the cost of wheeling or other infrastructure costs to get the power to its ultimate market.Table H‐2: Business Models for Select Project Configurations
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H.2 ASSUMPTIONS IN PROJECT COST ESTIMATES AND SCENARIOS
H.2.1 ESTIMATED DEVELOPMENT COSTS
The estimated development costs listed in Table H‐1 include all costs from concept to
commissioning, including the costs of this feasibility study. Assumptions for these costs are as
follows:
The ‘pre‐construction’ line item includes the estimated cost to obtain regulatory
approvals and permits, conduct resource studies that may be required by the resource
agencies, conduct technical studies, complete design documents for the project, conduct
contract negotiations, develop a business plan for the project, and similar pre‐
construction costs.
The next seven line items are for construction activities. These are organized by major
construction activity.
The ‘construction engineering’ line item includes inspection, review of technical change
order requests, assembly of record documents for the project, and related items that
occur during the construction phase of the project.
The ‘construction management/administration’ line item includes oversight of the
contractor(s), and management of the project finances, permits, and similar activities
during the construction phase of the project.
The ‘contractor margin’ line item is an estimated markup for contracted construction
services.
The ‘contingency’ line item is a 20% contingency applied to the entire development
budget estimate.
H.2.2 FINANCING
Assumptions about financing presented in Table H‐2 are as follows:
For scenarios without additional grants, 20% of the total development cost is contributed
owner equity, and the balance is raised as debt.
For scenarios with additional grants, grants are assumed to provide 80% of the total
capital costs, up to a maximum of $8,500,000. Owner equity is assumed to provide the
balance, up to a maximum of 20% of the total capital cost. Any remaining capital is
raised as debt.
All debt is assumed to be commercially financed at a 30‐year term at 6% interest.
Debt origination costs of 3% are assumed for items such as application fees, loan
guarantee fees, and/or other origination fees.
State or Federal grants can help reduce the amount of capital BCH needs to borrow for the
project. As shown in Table H‐2, such grants would enable BCH to lower the required sales
price for energy from the project, potentially expanding the available market for Burro Creek
energy. The eligibility of the project for grants will depend on a number of factors that are
specific to the various grant programs for which the project may be eligible.
Also, State or Federal loan programs can lower BCH’s borrowing costs for the project, which
would reduce annual debt payments, enabling BCH to lower the energy sales price. These loan
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programs typically offer below‐market interest rates, longer loan terms (up to 50 years), loan
guarantees, or a combination of these.
State and Federal loan and grant programs for which the project may be eligible are listed in
Section H.3 of this Appendix.
H.2.3 ESTIMATED ANNUAL PROJECT COSTS
H.2.3.1 General, Administrative, Operation, and Maintenance Expenses
Typical general and administrative costs for an IPP at Burro Creek include items such as
business insurance and management of the IPP’s business affairs.
The hydroelectric project will have operation and maintenance costs. This includes labor costs
for monitoring and maintaining the hydro systems as well as direct expenses for parts and
consumables. This will include activities such as plant inspections, maintenance, routine parts
replacement, and trail maintenance costs.
H.2.3.1.1 Taxes
As a for‐profit business, BCH will have to pay State and Federal taxes on earnings. The State of
Alaska currently has tax credit programs in effect that may partially offset BCH’s tax burden if
the current program is still in effect when the project is operational. Similarly, Federal energy
credit programs may partially offset tax liabilities.
Depreciation will largely or entirely offset tax liabilities in the early years of project operation.
H.2.3.1.2 Insurance
At a minimum, BCH will be required to carry standard business and liability insurance policies
for the project. Additionally, BCH may elect or be required to purchase boilermaker’s insurance
and related policies to protect the project against premature failure of capital equipment. BCH’s
financial instruments, power sales contract, and regulatory permits will likely contain language
stipulating what insurance policies BCH will be required to maintain.
H.2.3.1.3 Repair and Replacement
Most of the hydroelectric project systems and components have a very long useful life. The
intake, penstock, powerhouse, switchgear, turbine/generator, and power line all are expected to
have useful lives of 30 to 50 years or more. Some components will require periodic repair or
replacement. Minor components, such as pumps, actuators, control sensors, and similar
devices, are assumed to have a useful life of five years. The water turbines may need an
overhaul after about 15 to 25 years.
H.2.3.2 Return on Equity and Operating Margins
For debt and equity‐financed projects, an annual return on equity of 20% is assumed. For
partially grant‐financed projects, an annual return on equity of 12% is assumed. All cases also
provide a 10% margin on gross revenue to provide adequate cash reserves for the business to
weather unforeseen expenses such as major equipment failures, low water years, etc.
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H.2.4 ESTIMATED PROJECT REVENUES
H.2.4.1 Energy Sales
The amount of kWh available for sale from a given project configuration are calculated from the
hydrology model described in Appendix C. The net kWh available for sale are the average
annual amount less 10% for assumed forced outages and scheduled outages for maintenance.
Seasonal cases also discount the net kWh available for sale by 10% for forced and scheduled
outages.
H.2.4.2 Environmental Attributes
The environmental attributes (EA) of the recommended project can be marketed nation‐wide to
earn BCH additional revenue. The project’s EAs would be sold on the voluntary market, where
pricing for EAs varies. Prices were as high as $0.02 per kWh before the financial crisis of 2008,
and more recently have fluctuated in the range of $0.001 to 0.005 per kWh.
For several years, there has been an effort at the Federal level to implement mandatory
purchase of EAs. Such legislation would likely expand the market and stabilize the pricing for
EAs. It is unknown if or when such legislation would take effect, or what the final terms of such
legislation will be.
While EAs from the project are an additional potential revenue stream for BCH, no revenue
from EAs is assumed in this feasibility study.
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H.3 POTENTIAL FUNDING AND FINANCING OPPORTUNITIES
Several Federal, State and regional programs offer grants or loans for hydroelectric facility
development. Some Federal programs have lost funding in recent years, even though they are
still in effect. Some programs are outlined below. While this project seems to fit with these
programs in general, often judgment of the funding agency regarding economic benefit to the
public and other criteria will be determining factors for eligibility.
Currently, Federal regulations do not define hydroelectric power generation as renewable
energy, so hydro projects are not eligible for some Federal grants and loans. Legislation has
been presented to Congress that will redefine small hydroelectric projects as renewable energy
projects. If that legislation becomes law, additional Federal grant and loan opportunities may
become available for this project.
US Department of Agriculture Rural Development:
o Rural Energy for America direct loan and loan guarantee programs.
o Rural Energy for American grants program (no funds available)
o High Cost Energy program (no funds available)
US Small Business Administration:
o Small Business Grants
o Small Business Loans (18 programs)
Alaska Energy Authority (AEA)/Alaska Industrial Development and Export Authority
(AIDEA):
o AEA Renewable Energy Fund (grants)
o AEA Power Project Fund (loans)
o AIDEA Development Finance Program (loans)
o AIDEA Load Participation Program (loans)
Alaska Department of Commerce, Community and Economic Development, Division of
Economic Development:
o Rural Development Initiative Fund (loans)
o Small Business Economic Development Fund (loans)
Alaska State Legislature:
o Direct Legislative Appropriations
Juneau Economic Development Council:
Southeast Alaska Revolving Loan Fund
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APPENDIX I – ACRONYMS AND TERMINOLOGY
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ACRONYMS AND TERMINOLOGY
ac‐ft acre‐foot, acre‐feet. A measure of water volume equal to one acre covered in
water to a depth of one foot.
ADCED Alaska Department of Community and Economic Development
ADEC Alaska Department of Environmental Conservation
ADFG Alaska Department of Fish and Game
ADNR Alaska Department of Natural Resources
AEA Alaska Energy Authority
ATV All Terrain Vehicle
APA Alaska Power Authority (predecessor to the AEA)
AS Alaska Statute
BCH Burro Creek Holdings, LLC
BCR benefit‐cost ratio
BLM Bureau of Land Management
cfs cubic feet per second
coanda effect The tendency of a fluid jet to stay attached to a smoothly convex solid
obstruction. A common example is the way a stream of water, as from a faucet,
will wrap around a cylindrical object held under the faucet (such as the barrel of
a drinking glass).
COE U.S. Army Corps of Engineers
discharge A synonym for stream flow. Flow and discharge are used interchangeably in this
report.
DOE U.S. Department of Energy
Environmental
attributes
The term environmental attributes is used by the utility industry to describe the
desirable aspects of electricity that is generated from environmentally benign
and/or renewable sources. Environmental attributes are tracked, marketed,
bought, and sold separately from the physical energy. Separating the
environmental attributes from the physical energy allows customers or
ratepayers to elect to buy sustainable or ‘green’ energy even if it is physically
unavailable from their electric utility.
ft foot, feet
FY fiscal year
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gal gallon(s)
gross head The topographic elevation difference between the headwater elevation of the
hydroelectric project and the turbine(s) in the powerhouse (see also ‘net head’).
HDPE high‐density polyethylene
in inch, inches
isohyet a map contour connecting areas of equal precipitation.
kV kilovolt, or 1,000 volts
kVA kilovolt‐amp
kW kilowatt, or 1,000 watts. One kW is the power consumed by ten 100‐watt
incandescent light bulbs.
kWh kilowatt‐hour. The quantity of energy equal to one kilowatt (kW) expended for
one hour.
MHW mean high water
mi mile, miles
MW megawatt, or 1,000 kilowatts
net head The gross head on a project less losses due to friction in the pipe, fittings, valves,
etc. at the project’s full design flow.
Obermeyer gate
A hydraulic gate that when open lays flat on the bottom of a creek or river. The
gate has a hinge along its upstream edge that is secured to the creek bottom
(typically to a concrete sill formed in the creek bed). The gate is closed by
inflating a rugged rubber bladder installed underneath the gate. The bladder
lifts the gate to an angle of approximately 45 degrees, impounding water behind
the gate. These gates are advantageous for passing large debris and accumulated
bed load (sand, gravel, and cobbles) through a small diversion impoundment.
O&M operating and maintenance
OMR&R operating, maintenance, repair, and replacement
PCE Power Cost Equalization Program
PDO pacific decadal oscillation. A climate phenomenon similar to the ‘El Nino / La
Nina’ climate fluctuations in the equatorial Pacific Ocean. The PDO is situated in
the north Pacific, and fluctuates on a time scale of a few decades.
P.E. Professional Engineer. Licensed in the State of Alaska.
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Plant capacity factor
The plant capacity factor is the amount of energy the plant generates in a year
divided by the amount of energy that would be generated if the plant could run
at full output 100% of the time. This number is less than 100% due to factors
such as limited water flow during the winter months or system outages for
repair or maintenance.
rpm revolutions per minute
SDR standard dimension ratio
sq.mi. Square mile
USFS U.S. Forest Service
USGS U.S. Geological Survey
V volt
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APPENDIX J
APPROPRIATE TECHNOLOGY REPORT: HYDROELECTRIC SYSTEM
AT BURRO CREEK
(GENE RICHARDS, 1982)
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APPENDIX K
DRAFT REPORT REVIEW COMMENTS AND RESPONSES
polarconsult a la ska, inc.
1503 West 33rd Avenue, Suite 310
Anchorage, Alaska 99503-3638
Phone: (907) 258-2420
FAX: (907) 258-2419
M E M O R A N D U M
111117-BURROREPORT_AEACOMMENTS.DOC
DATE: November 17, 2011
TO: Jan Wrentmore
FROM: Joel Groves, Polarconsult Project Manager
SUBJECT: Response to AEA Review Comments on
Burro Creek Hydroelectric Study
CC: Final Report Appendix K
The Client Review Draft of the Burro Creek Hydroelectric Feasibility Study Final Report was
provided to the Alaska Energy Authority (AEA) on October 31, 2011. The AEA provided
comments on November 9, 2011.
AEA comments and Polarconsult / Southeast Strategies responses are summarized below. As
appropriate, AEA’s comments have been incorporated into the final release of the Burro Creek
Hydroelectric Feasibility Study Final Report, dated November 2011.
AEA Comments Received (Polarconsult/Southeast Strategies responses in BLUE)
1. Table ES-1: Capital construction costs in this table range from $2,585/kW to $3,909/kW. AEA
is currently using the figure of $5,500/kW for estimates of hydropower at this level of study as
the low end cost. Projects with significant upcharge features such as remote sites, multi miles
of high pressure penstocks and several miles of submarine cables will likely cost more. All in all,
it is expected these reported capital costs are far below what is believed to be reasonable for
budgeting at the reconnaissance level in today's market.
The cost estimates in Table ES-1 are based on analysis of unit costs and quantities for major
project materials, equipment, and labor, and not on a simplified $/kW metric. While a $/kW
metric is useful in comparing and evaluating projects, it is important to recognize that $/kW
varies strongly with installed capacity and other factors. For example, $/kW for small hydro
projects in Alaska under 300 kW can be expected to be $10,000 to $15,000 per kW or more, 2
to 3 times greater than the cited AEA metric. Recent experience in Skagway at Kasidaya
Creek (commissioned in 2009), which is similar in many regards to Burro Creek, is in line with
the cost estimates in this study, when adjusted for site specific differences.
It is important to understand the limitations of cost estimates at the level of analysis
performed for this study. Because this study did not include detailed geotechnical
investigations, engineering design, and similar in-depth analyses, there are unknowns that
may result in costs significantly different than those cited in this study. The budget
contingency included in the construction cost estimate is intended to accommodate these,
based on standard engineering practice. Future investigations will provide the data to refine
these cost estimates. Because of these factors, the accuracy of these cost estimates can be
considered as + / - 30%, as is typical at this level of study.
P OLARCONSULT M EMORANDUM
Page 2 of 3
2. Regarding export of power to the Yukon (Canadian) grid (page ii): The report states the
proposed project would meet the needs of Yukon Energy and they would be willing to extend
their transmission lines to the U.S. - Canadian border to purchase the power from Burro Creek.
This approach would appear less speculative if an offer letter from the Canadian utility were
provided in the appendix explaining the conditions that would have to be met for that to take
place.
Correspondence with Hector Campbell of Yukon Energy regarding an interconnection
between the Yukon and Upper Lynn Canal grids and purchase of Alaska hydropower over this
interconnection is attached to this memo.
3. The Executive Summary of the report fails to mention several other potential hydroelectric
projects presently under consideration for study and future development in the Upper Lynn
Canal region, including Walker Lake (1 MW), West Creek (25 MW), Connelly Lake (12 MW) and
Schubee Lake (5 MW). These alternative projects will compete for the same limited markets
that Burro Creek would propose to satisfy.
These other prospective hydro projects have been added to the Executive Summary
narrative. It is likely that these projects will improve the market opportunities for Burro
Creek, rather that compete against Burro Creek. This would occur by either (1) opening up
the Yukon Territory market, or (2) increasing the capacity of the Upper Lynn Canal grid so that
cruise ships docked in Skagway and Haines can be served. The Upper Lynn Canal grid would
need a combination of storage and run-of-river hydro projects in order to serve the variable
10 to 50 MW combined load of the cruise ships that dock in Skagway during the summer
months.
4. The page numbers for the Executive Summary need to be adjusted.
This has been corrected.
5. Unless the project is limited to within the boundary of the USS 1560 property, the five year
completion time for project first power is overly optimistic. The project will be subject to FERC
licensing jurisdiction if federal lands are impacted. Note that all project configurations found in
Table ES-1 will require FERC to be the licensing authority since BLM lands are impacted by
project features. FERC's 5 MW exemption may apply depending upon the project configuration.
The five-year schedule is based on the following assumptions:
1. BCH makes a near-term decision to aggressively develop the project, and is able to
secure power sales commitments in a timely fashion.
2. The project uses FERC’s Integrated Licensing Program, which provides for a three-year
licensing period. A FERC exemption would have a similar or shorter time-frame.
3. Construction is completed in two years.
Hydro projects frequently experience schedule creep and delay. Such delays generally are
due to permitting delays and shifting environmental study requirements, but can be caused
by a diverse range of project-specific issues. The project schedule presented in the report is a
P OLARCONSULT M EMORANDUM
Page 3 of 3
near-best case schedule, and delays are a real possibility. The report narrative has been
revised to clarify these points.
6. The data in Table 2-4 should be labeled as in Fiscal Years of the State of Alaska (July 1 to June
30).
A footnote has been added to Table 2-4 specifying that the data is in state fiscal years.
7. The title of Table D-1 needs to be edited.
This has been corrected.
8. In Section D.1 Maximum Possible Flood, the following statement is offered: "The estimated
2- year flood flows in Table D-1 are approximately 105% of the highest observed flows recorded
at Burro Creek in 1.7 years of measurements." From Table D-1, the 2-Year Flood Flows have
been calculated at 292 cfs. In fact, there were five high observed flows captured in the stage
data, at 491 cfs on 9/22/11, 470 cfs on 9/21/11, 439 cfs on 8/21/11, 390 on 8/20/11, 321 cfs on
11/4/10, and nine other events that exceeded the 292 cfs figure. Given this data, the
calculations of the 2 year flood data and the Maximum Possible Flood using the USGS methods
appear to have significantly under-estimated the predicted high flow events.
There was an incorrect entry for the ‘storage’ parameter input to the USGS model used to
estimate flood flows. The flood flow and observed peak flow estimates in Table D-1 have
been corrected.
9. Regarding the discussion of fish populations in Burro Creek in Section E.2: It has been AEA's
experience that ADFG will require environmental flows to support Dolly Varden populations.
This may impact your energy generation estimates. Additionally, the narrative refers to salmon
visiting the creek but fails to mention how far up they can travel or if the waterfalls act as
natural barriers.
ADFG requirements are based on ADFG’s comments regarding this specific project. In the
event ADFG does determine minimum flows are required for Dolly Varden or other species,
the economic impact on the project would depend on final powerhouse siting. If the
powerhouse is located above the waterfall at site ‘A’ (see Figure A-3), fish habitat flows
would not be altered from natural conditions. If habitat flow requirements did curtail project
generation, this impact would be bracketed by the ‘full sales’ and ‘partial sales’ power
generation scenarios considered in this study.
The approximately 15-foot tall waterfall at mile 0.13 (see Photograph B-2) is a barrier to fish
passage.
These points have been clarified in the Appendix E narrative.
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report Appendix K
-------- Original Message --------
Subject: RE: Burro Creek Hydroelectric in Skagway
Date: Mon, 21 Nov 2011 18:39:04 -0800
From: Hector Campbell <Hector.Campbell@yec.yk.ca>
To: Linda Snow <ljsnow@ak.net>
Linda,
Sorry for the delay in responding to you.
1/ Yukon Energy is interested in a connection to Skagway to potentially import renewable
energy from the Skagway grid when it is available or to export energy to Skagway when it is
available in Yukon and needed in the Skagway power grid. For the grid intertie to be
constructed, there would have to be favorable economics on both sides of the border. Yukon
Energy is also reviewing the potential development of up to two hydro sites in Yukon along the
Skagway road whose economics would be improved by an transmission line along the Skagway
road between Carcross and the Alaska border.
2/ The economics of extending the existing 34 kV line from Carcross to the Alaska border would
have to be assessed based on its maximum load carrying capacity (in MW’s) as that would be
the primary economic factor, in addition to the amount of power available (MWH’s) for import
and/or export.
3/ There are no set conditions I can give you. The economics and decisions would be approved
on a case by case basis by the Yukon Utilities Board (YUB), our financial regulator in Yukon. In
general they will look at both the short term and long term costs of this option compared to
alternatives available to Yukon Energy at the time of our application to the YUB.
4/ There will be a max amount of load carrying capability in the lowest cost of connection option
utilizing existing 34 kV transmission in both Yukon (Whitehorse to Carcross) and Skagway
(Skagway to Goat Lake). To go above this threshold to improve the load carrying and energy
transfer potential would require a new transmission line at 69 or 138 kV from Whitehorse all the
way to Skagway which would result with a significant transmission cost increase.
Hector Campbell. P. Eng., M.B.A.
Director, Resource Planning & Regulatory Affairs
Yukon Energy Corporation
Ph: (867) 393-5331
Cell:(867) 334-7070
Fax: (867) 393-5323
Email:hector.campbell@yec.yk.ca <mailto:hector.campbell@yec.yk.ca>
Website: www.yukonenergy.ca
From: Linda Snow [mailto:ljsnow@ak.net]
Sent: Thursday, November 17, 2011 9:57 AM
To: Hector Campbell
Subject: Fwd: Burro Creek Hydroelectric in Skagway
Importance: High
Mr. Campbell,
I just left you a voice mail message about this. Alaska Energy Authority is
reviewing the feasibility study, and they were asking if we could get some
conditions in writing from you for the final. Please let me know if you get this
message. I am gone from the office a lot this week, but you can reach me on my
Burro Creek Holdings, LLC
Burro Creek Hydroelectric Study Polarconsult Alaska, Inc.
November 2011 – Final Report Appendix K
cell phone at 907-209-3603. Once the feasibility study is finalized, we would be
happy to send you a copy. Thanks.
Linda Snow
-------- Original Message --------
Subject:Burro Creek Hydroelectric in Skagway
Date:Fri, 11 Nov 2011 08:17:21 -0900
From:Linda Snow <ljsnow@ak.net>
To:Hector.campbell@yec.yk.ca
Mr. Campbell,
We spoke a couple of months ago about plans for Burro Creek hydroelectric near
Skagway to expand their facility and offer hydro power for sale. You told me that
Yukon Electric may be interested in purchasing Burro Creek power. From our
conversation, I understood that Yukon Electric is considering a couple of projects
near Tutshi Lake south of Carcross. One of those projects being considered is a
pump storage project, which you felt might work well with Burro Creek upgrade. I
understand that the Yukon Electric power line currently reaches from Whitehorse
to Carcross, and if the Tutshi Lake projects are developed, that line would be
extended to within about 35 miles of the Alaska Border. You said that Yukon
Electric may be willing to continue that line to the Alaska border in order to
connect with, and purchase Burro Creek power.
We are completing the Burro Creek hydroelectric upgrade feasibility study.
Would it be possible for you to reply to this e-mail with a list of conditions that
would need to be met by Burro Creek hydroelectric in order for Yukon Electric to
extend your power line to the Alaska Canada border to purchase Burro Creek
power? Also, we are looking at several project configurations with various
outputs. Is there a minimum and maximum amount of power you are interested in
purchasing that would make your line extension more probable?
I hope you are having a good holiday. Please don't hesitate to contact me if you
have questions or need further clarification.
Linda Snow
Southeast Strategies
Juneau, Alaska
Phone: 907-780-6106
Cell: 907-209-3603