HomeMy WebLinkAboutRural Hydro Elecric Assessment Phase II Report 1-9-1998RURAL HYDROELECTRIC ASSESSMENT AND
DEVELOPMENT STUDY:
PHASE II REPORT
Prepared
for
Alaska Department of Community
and Regional Affairs
Division of Energy
by
Locher Interests LTD.
Anchorage, Alaska
with
Harza Northwest, Inc.
University of Alaska Anchorage,
Institute of Social and Economic Research
January 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
TABLE OF CONTENTS
SECTION 1: SUMMARY OF FINDINGS
1.1 Old Harbor..............................................................................................................................1.1
1.2 Unalaska.................................................................................................................................1.2
SECTION 2: INTRODUCTION
2.1 Background.............................................................................................................................2.1
2.2 Scope of the Assignment........................................................................................................2.1
2.3 Sources of Information and Methods......................................................................................2.2
2.4 Acknowledgments...................................................................................................................2.6
SECTION 3: OLD HARBOR
3.1 Location..................................................................................................................................3.1
3.2 General Description of the Area.............................................................................................3.1
3.3 Existing Power System...........................................................................................................3.2
3.4 Hydroelectric Development Alternatives.................................................................................3.5
3.5 Selected Alternative................................................................................................................3.6
SECTION 4: UNALASKA
4.1 Location..................................................................................................................................4.1
4.2 General Description of the Area.............................................................................................4.1
4.3 Existing Power System........................................................................................................4.2
4.4 Hydroelectric Development Alternatives.................................................................................4.6
4.5 Selected Alternative................................................................................................................4.8
SECTION5: REFERENCES.....................................................................................................................5.1
SECTION6: EXHIBITS.............................................................................................................................6.1
SECTION7: PHOTOGRAPHS.................................................................................................................7.1
SECTION 8: APPENDICES......................................................................................................................8.1
LOCHER INTERESTS, LTD. PAGE I JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
1. SUMMARY OF FINDINGS
1.1 OLD HARBOR PROJECT
1.1.1 Technical Evaluation
The selected development is essentially the same as that proposed by Polarconsult. It is a run -of stream,
transbasin diversion that diverts water from East Fork Barling Creek via a penstock to a powerhouse
located at elevation 80 on Lagoon Creek. The project utilizes 3,293 lineal feet (If) of new 16-inch (in)
i diameter HDPE pipe and 6,966 If of new 16-in diameter steel pipe to provide water at a net head of 695
feet to a Pelton turbine unit with a nominal output of 500 kW and efficiency of 0.88. The nominal rated
discharge is 12.4 cfs, with minimum and maximum discharges of 1.3 and 12.4 cfs. Stream discharge
would be available for power generation every day of the year. Average annual energy output from this
project is estimated at 3,425,000 kWh per year, and would partially replace current diesel energy
production operations.
This project is large for the existing system toad. However, a smaller installation would have minimum
associated cost savings, and from a long-term planning perspective appropriate for development of
hydroelectric developments, it is reasonable to develop the potential of the proposed site with maximum
efficiency.
1.1.2 Environmental/Regulatory Evaluation
The proposed Old Harbor Hydroelectric Project is currently in the Federal Energy Regulatory Commission
(FERC) licensing process. An Applicant Prepared Environmental Assessment (APEA) process is being
pursued and preliminary agency consultation has been completed, along with some initial field work on
fisheries, birds, and cultural resources.
To date, no environmental issues have been identified which would preclude or seriously impact the
applicants ability to develop this project. It is likely that the project will have some impacts on
anadromous fish habitat in lower Barling Creek, although these effects should be offset by increased flows
in Lagoon Creek. Further, there is significant intervening drainage between the point of diversion and the
downstream fish habitat in Barling Creek so that impacts will be substantially reduced.
The project is to be mainly located on Kodiak National Wildlife Refuge lands, including some lands
originally patented to the Old Harbor Native Corporation and later purchased in fee for the refuge. These
lands have certain restrictive covenants attached which, unless altered, would preclude development of
this project However, it appears that the Federal and State agencies involved are both able and willing to
take the necessary steps to modify these covenants, so as to allow project development. Should either
the State of Alaska or the Department of the Interior not wish to cooperate in addressing this issue,
however, land status could become a fatal flaw for the project.
1.1.3 Economic/Financial Evaluation
For purposes of our analysis we have developed two cost estimates for each project. One, designated
herein as the force account process estimate, is based on the assumption of use of local labor, as
appropriate, to reduce construction costs, combined with other cost reducing measures such as purchase
of the turbine and generator from a small recognized manufacturer who is unable to provide equipment
warranties but offer significantly lower prices. The second estimate, denoted as the standard construction
process estimate, assumes a standard contractor construction process, along with purchase of generation
equipment from a major manufacturer, able to provide complete warranties at higher costs. These two
estimates reflect different levels of risk for cost overrun during construction, construction delay, and post
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ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
I construction or operational problems. Our construction cost estimates for the Old Harbor Project are
$2,767,800 for a force account process and $3,425,200 for a standard construction process.
The economic viability of the Old Harbor Project is sensitive to these costs, as well as to two critical
parameters: (1) system load growth, and (2) future fuel prices. Using the force account process cost
estimate, the project has positive net economic benefits under all combinations of assumptions concerning
load and fuel prices. Using the standard construction process cost estimate, it has a net positive
economic benefit only if high annual load growth (3.0%) and fuel price increases (1.5%) are assumed.
Using a mid -range estimate for future growth in load and fuel prices (2.0% and 0.5%, respectively) the
project has a net positive benefit of $775,000 for the force account process cost and a net negative benefit
of-$260,000 for the standard construction process cost.
Financial analysis, based upon use of the force account process cost indicates that AVEC's system -wide
cost of service would be slightly higher with the hydroelectric project through the year 2012, after which it
would fall slightly. However, the effects on revenue requirements are minor (ca 1.0% increase until 2012;
ca 0.5% decrease thereafter). Assuming the standard construction process cost, system -wide cost of
service would increase by a maximum of 1.7% initially, but would drop below 1.0% by year 2010.
j 1.1.4 Recommendations
J The Old Harbor Projects economic/financial viability is sensitive to cost. The cost estimates developed for
this analysis differ substantially from that provided by Polarconsult, the consultant currently pursuing
development of this project on behalf of the Alaska Village Electric Cooperative (AVEC). Our force
account process estimate is higher than the $1,442,403 estimate (as adjusted to 1997 dollars) developed
by Polarconsult. While our analysis indicates that the project still would be economically viable for our
more conservative force account cost estimate, the difference between our estimate and the Polarconsult
cost is striking. Based upon our current understanding of the project, it is felt that the substantially lower
cost estimate currently being used by AVEC includes assumptions that substantially increase the risk of
j cost overruns and potentially costly delays in construction and/or operational problems. These
discrepancies in costs, and the assumptions concerning the approach to completion of the project which
underlie them, should be thoroughly explored by AVEC and DOE before making a final commitment to this
project
In addition to its sensitivity to cost, the discrepancy between the size of this project and Old Harbors
existing load make it sensitive to load growth. Any developments in Old Harbor which might significantly
increase system load would likely improve project economic viability. The Village of Old Harbor should
explore increased use of electric heat as well as installation of fish processing facilities with future
development plans.
Prior to final design of the project, it will be prudent to gather as much recently gaged stream data as
possible from Polarconsult for the active gage on Barling Creek. These additional data would refine the
hydrologic analyses used for this report.
1.2 UNALASKA PROJECT
1.2.1 Technical Evaluation
Five alternatives for developing the hydropower potential of Pyramid Creek were evaluated. The selected
project taps into the existing City water supply line at the treatment building and conveys excess water to
a powerplant at tidewater. The project would utilize 6,000 If of the existing 24-in diameter ductile iron pipe
and some 2,500 If of additional 24-in diameter steel pipe to provide water, at a net head of 451 feet, to a
LOCHER INTERESTS, LTD. PAGE 1.2 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Francis turbine unit with a nominal output of 600 kW and efficiency of 0.88. The nominal rated discharge
is 17.8 cfs, with minimum and maximum discharges of 8 and 22 cfs. Stream discharge would be available
for power generation 61% of the time. Average annual output from this project is estimated at 2,570,000
kWh per year, and will supplement current diesel energy production operations.
1.2.2 Environmental/Regulatory Evaluation
The proposed Unalaska Hydroelectric Project is not currently being formally pursued. Thus, licensing and
permitting programs will have to be initiated by the City of Unalaska before official resource agency
positions on the project can be determined. However, informal conversations with resource specialists
indicate that concerns for pink and coho salmon habitat in lower Pyramid Creek and resident dolly varden
habitat below Icy Creek Reservoir will require resolution. Fisheries mitigation measures, including
instream habitat modifications and/or provision of fish flow releases at Icy Creek Reservoir, are likely to be
required. Our analysis has included an evaluation of the feasibility of both types of mitigation and indicate
that either or both could be implemented without loss of project economic viability (although benefits would
be reduced).
Previous investigators attempted to obtain a ruling from FERC that no federal license would be required
for a hydroelectric development on Pyramid Creek. It is not known if this attempt was successful.
Because anadromous fish and Native Corporation lands would be effected by project development,
federal involvement in the project is required, and it is unlikely that a FERC exemption would be advisable.
In fact, it is likely the FERC process would be beneficial in that it would provide a known regulatory
compliance framework for the resource agency participation required for project development.
The project, as proposed, would be located on Ounalaska Native Corporation (ONC) lands (the penstock),
Crowley Marine Services land (the powerhouse), and a private parcel owned by a local resident (an
access road). There should be no restrictions to development of the project on these lands, although
individual land owners may or may not be amenable to the proposed development.
Finally, the area where the project access road, powerhouse, and tailrace are to be located has been
intensively used for industrial purposes in the past. Thus, there is some potential for contamination of the
soils by materials classified as hazardous or toxic, which would require remediation as a condition for
project development. The probability of such conditions cannot be determined at this time. Should such
contamination be found, project costs could increase substantially.
1 1.2.3 Economic/Financial Evaluation
1 Our cost estimates for the Pyramid Creek Project are $1,557,900 for the force account process and
$2,177,800 for a standard construction process.
Project economics for this project are sensitive only to future fuel prices. It has net positive economic
benefits under all cases analyzed. Assuming force account process cost and high fuel price growth
(1.5%), net benefits of the project are $2,326,000. Using the standard construction process cost and the
low fuel price growth, the net benefits are still positive at $848,000. Assuming a mid -range increase in fuel
price and the force account process cost, the net benefits are $1,673,000.
The Pyramid Creek project would play only a small role in the City of Unalaska's overall utility operation.
The Project's financial impact is also limited. Financial analysis shows that with hydropower, very minor
(1.0%) increases in system cost of service occur, assuming standard construction process costs, until
about year 2010. However, using the force account process cost estimate, the cost of service with the
hydropower is slightly lower (0.1%) than without hydropower costs, almost immediately. Cost of service
LOCHER INTERESTS, LTD. PAGE 1.3 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
I
reductions reach levels of about 1.5% by year 2020, after which differences between the with and without
hydropower costs essentially disappear.
1.2.4 Recommendations
Impacts of the selected project development on the small population of anadromous fish which reside in
Pyramid Creek below the canyon is likely the most critical issue to be resolved. While it appears that
fisheries mitigation or even enhancement is possible, both through provision of minimum flow reservations
and by instream habitat enhancement, agency willingness to work towards a solution is not guaranteed.
Formal consultation on this project, to be completed once a decision to proceed has been made, should
immediately focus on resolution of this issue. Additionally, prior to final design of each project, it may be
prudent to gather as much recently gaged stream data as possible from DNR for the active gages on
Pyramid Creek. These additional data would refine the hydrologic analyses used for this report.
LOCHER INTERESTS, LTD. PAGE 1.4
JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
2. INTRODUCTION
2.1 BACKGROUND
This report presents the results of the Phase II portion of contract DOE 96-R-004, Rural Hydroelectric
Assessment and Development Study.
Phase I of this contract, completed in August of 1997, included:
1. The development of a Microsoft AccessTM database, containing information on
existing and potential hydroelectric projects in Alaska.
2. Ranking and screening of 1,100 potential sites by their technical, environmental, and
economic suitability for development as power sources for rural communities currently
participating in the Power Cost Equalization (PCE) program.
1 3. Selection of a smaller subset of projects for more detailed evaluation.
I
A Phase I report written by Locher Interests, LTD. (Locher) was provided to the Alaska Department of
Community and Regional Affairs, Division of Energy (DOE) on August 18, 1997.
The Phase I report recommended that two potential rural Alaska hydroelectric developments be carried
forward to a more detailed Phase II evaluation:
• the Old Harbor Project on
Island, and
• the Pyramid Creek Projec
Unalaska.
2.2 SCOPE OF THE ASSIGNMENT
The scope of Phase it includes examination of the environmental, engineering, and economic viability of
the above two potential hydroelectric projects in greater detail and production of a reconnaissance level
evaluation with recommendations for DOE concerning the provision of financial support for their
development. The work tasks defined for Phase it analysis include:
1. Obtain additional data for project evaluation.
2. Conduct site visits to evaluate technical project viability.
3. Confirm project energy/capacity capabilities.
4. Confirm proposed project design concepts.
5. Refine project cost estimates.
6. Perform economic and financial analyses of both projects.
7. Prepare a written Phase II report.
LOCHER INTERESTS, LTD. PAGE 2.1
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ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
2.3 SOURCES OF INFORMATION AND METHODS
2.3.1 Existing Systems
Assessment of the hydroelectric developments schemes presented herein is based in large part on review
of:
• studies of the hydroelectric potential in the two communities done by others,
• information on existing generation systems, energy demand, and power production
statistics provided by the DOE and the utilities serving the two communities,
j information on utility operations and maintenance costs as provided by the two
J communities or their utilities, and
• general data concerning the project area land use, ownership, and environmental and
socioeconomic conditions, as available, from the literature and/or resource agency
files.
These data sources were supplemented by additional information obtained during a three-day field
reconnaissance of each site, conducted by a team consisting of a civil engineer/power planner, a
hydrologist, and an environmental scientist.
j Information on the existing generation systems was obtained from the utilities (the Alaska Village Electric
Cooperative for Old Harbor and the City of Unalaska, Department of Public Utilities). Data on energy
generation (annual and monthly power generated, purchased, sold, and monthly peak demand) from
these two systems were obtained from DCRA/DOE Power Cost Equalization (PCE) program monthly
statistics.
Specific methods of evaluation applied to these projects is detailed below.
2.3.2 Engineering/Technical Evaluation
f Project Configurations: As indicated herein, several studies have been performed for each of the
localities, each with several potential configurations. Each configuration was briefly examined and the
1 selection narrowed down to what was believed to be the most likely layout(s) for further study. Subjective
criteria were applied including: consideration of available head and flow at each location, construction and
operations access to project features, potential project costs, and constructability. Upon narrowing the
alternatives to a reasonable number, each was examined in more detail and considered energy output,
project layouts, and construction costs.
Energy: A computer -modeled energy study was performed for each alternative. The energy model used
the following input values:
i • average daily flows
• reservoir elevation
1 • powerhouse elevation (tailwater or centerline runner)
J • penstock diameter and material properties (friction coefficient)
• number of bends from 22.5° to 90`
1 • turbine size (rated output)
• turbine efficiency curve
• generator efficiency
• transformer efficiency
LOCHER INTERESTS, LTD. PAGE 2.2 JANUARY 09,1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
The model used the Energy Equation:
E=QxHxex24
11.81
1 where,
E = average daily energy output in kilowatt hours (kWh),
Q = flow passing through the turbine in cubic feet per second (cfs),
H = net head sensed by the turbine in feet (gross head minus pipe system head losses), and
e = combined efficiency (et x e, x e,) of the turbine (et), generator (e9), and transformer (e,).
�( Stream flows were generated as indicated below. The elevation difference from the point of diversion to
f the powerhouse (gross head) was taken from USGS maps, project drawings, or previous reports. The
estimated penstock alignment was based on the available mapping and limited field observations. The
size of the penstock was estimated based on model output, no attempt was made at this phase of study to
optimize the pipe diameter. Contributing pipe system head losses input into the model included estimated
pipe friction losses (using Manning's Equation and roughness coefficients), entrance losses, bend losses,
and valve losses. Representative unit turbine efficiency curves were input into the model together with
l minimum and maximum unit flows for the turbine technology employed and unit flow vs. efficiency.
1 Generator and transformer losses were taken as constants.
"l The proposed projects lack any measurable storage and were considered as run -of -stream type
J installations. Therefore, the gross head was considered constant for each site. In such installations, the
reservoir level is continually monitored and the turbine gate or nozzle position is controlled to maintain a
constant reservoir level. The model examined each average daily flow value to see if it fell within the
range of operation of the turbine selected. If the flow was less than required to operate the turbine at
minimum output, then no energy was generated for the day. If the flow exceeded the maximum flow
allowable to be used by the turbine, then the turbine flow was limited to its maximum amount and the
j remainder was considered as spill past the diversion. Based on the comparison of the average daily flow
# with the unit turbine efficiency curve, a daily efficiency was computed. Head losses are a function of flow
and, therefore, each daily turbine flow was used to compute total estimated head loss in the penstock.
The net head was computed by subtracting the daily penstock head loss from the constant gross head.
Once turbine flow, net head, and efficiency were known, the energy equation (above) was applied and a
daily energy output computed. Each daily energy output was summed by month and by year. By varying
the penstock diameter and turbine size, various average annual energy outputs were computed. This led
to a preliminary optimization of the hydroelectric plant.
Results of the energy model studies are presented in detail in Appendix A.
1 Costs: A preliminary layout of each plant alternative was performed in order to estimate quantities of
materials used. The various components considered included diversion structure, intake structure,
penstock, access road(s), powerhouse, electro-mechanical equipment, tailrace, substation, and
transmission line. Once quantities were estimated, cost estimates were prepared based on regional
material and labor rates, and current equipment and shipping costs. Initial cost estimates were developed
utilizing traditional engineering and construction approaches to the projects, although an attempt was
made to apply design standards and construction approaches appropriate to a small run -of -stream
development to be constructed in Alaskan communities, avoiding the inclusion of unnecessary or
expensive ancillary equipment while providing for shipping expenses to rural areas.
A spreadsheet, used to compute project costs, was used to compute labor, material, and equipment costs
based on the quantities and components identified for the preliminary layouts. This spreadsheet was
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1
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
developed to allow variation in the assumptions utilized concerning labor costs and labor efficiency to test
the feasibility of a local labor approach to project construction, as well as variations in the factors applied
for contractor profit with overheads and contingencies. As a part of the final evaluation of the selected
projects, a series of runs of the cost spreadsheet were conducted, with associated discussions of the
perceived level of risk associated with each. This information was utilized in developing final
recommendations concerning project feasibility.
Results of the cost estimates are detailed in Appendix B.
2.3.3 Hydrology
Data available for hydrologic analysis was obtained from various sources. DNR provided a final stream
gaging report for Old Harbor (DNR, October 1996) and a preliminary gaging report for Unalaska (DNR,
August 1996). Polarconsult provided a spreadsheet of reservoir elevations and spill over the weir, as
available, for Icy Creek from 1991 to 1994. The City of Unalaska, Department of Public Works, provided
water production logs from January of 1991 through September of 1997 of reservoir withdrawal required to
meet water demand. AEA provided the Dowl Engineers' supplemental data reports of gaged stream data
for Midway Creek near the Old Harbor project site from their library. Via the internet, the U. S. Geological
t Services (USGS) and National Weather Service (NWS) provided long-term stream discharge and climate
! data for miscellaneous stations near the sites.
Predicted stream flows and water resource availabilities were calculated for each project based upon local
stream gaging records and long-term precipitation data recorded nearest to the watershed(s) of interest,
with local corrections for topography (elevation) and drainage areas.
The Department of Natural Resources (DNR) contracted in 1993 with the DCRA/DOE for the village of Old
Harbor, and in 1994 with the City of Unalaska, to provide streamflow characteristics for small hydroelectric
power development near each community. At the Old Harbor site, two stage gages were installed by DNR
as located in Exhibit Al. The lower gage site, receiving runoff from 4.6 sq mi, located 150 feet (ft)
downstream of the confluence of the east and north forks at elevation 490, was in operation from 1993
through 1996, but has since been abandoned. The upper gage, installed in October of 1995, located on
the east fork at elevation 800, is near the proposed diversion. Still operable, the station is recording
average daily flows and being maintained by Polarconsult, Inc. Unfortunately, current data have not
recently been downloaded and were not available for this study. As installed, the upper gage site
captures runoff from 38% of the same drainage area as measured at the lower gage. At Unalaska, DNR
installed five stage gages along the Icy Creek drainage at the locations shown in Exhibit 61: two in the
upper basin of Icy Creek, one just above its confluence with the East Fork, one on the East Fork just
above the confluence, and one near tidewater on Pyramid Creek. Four of these five gages remain in
operation today, though data used for Phase II calculations were from the period of record of March 30,
1994 through April 30, 1996. More recent data, including high flows for a February 1997 flood event, are
not yet available, but will be as DNR completes their 1997 report.
Precipitation records are currently being measured and recorded by the NWS for meteorological stations
located near both project sites. For Barling Creek (Old Harbor), previous reports have used precipitation
data recorded near the City of Kodiak, 70 mi northeast of Old Harbor, to characterize Baring Creek
discharges. Climate Vends across Kodiak Island indicate a marked increase in precipitation received from
the northwest to the southeast regions of the island. Thus, additional precipitation or meteorological
stations on the island were examined for proximity to Old Harbor. Of these stations, Shearwater Bay,
located 15 mi northeast of the site, likely receives the most similar frequency, duration, and intensity of
storms as do the hills directly north of Old Harbor due to its location on the island, proximity to Sitkalidak
Bay, and similar inland terrain. For Pyramid Creek (Unalaska), average daily precipitation records have
been recorded at the Dutch Harbor airport from 1922-1954 and 1982 until present, accumulating into a 38-
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ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
year historical record and long-term daily average. The station is approximately 4 mi northeast of the
Pyramid Creek basin, and most likely defines the character of precipitation in the study basin.
Precipitation measurements recorded for the gaging period -of -record were compared with the much
longer local historical precipitation record available to characterize current climate trends with long-term
averages. The measured discharge data were adjusted in proportion to the variance of the associated
daily precipitation from the long-term historical daily precipitation average. Then, the mean and standard
deviation for each adjusted average daily flow measured during the period of record were used to
augment the historical record by providing synthesized data with similar population statistics. Using this
method, a Pearson Type III distribution was assumed, and a 10-year gaged record was stochastically
created from the shorter term (4 years for Old Harbor, 3 years for Unalaska) stream records. A 10-year
simulated record is within standard acceptable limits of 3X to 4X the number of years of record. These
1 daily average streamflow, data were then corrected for various points of interest along the watercourse,
11 based upon elevation and contributing drainage area(s). For Pyramid Creek, an elevation adjustment
factor was calculated as 0.0036 cfsm using in -line gages, 1.2 mi apart. For Barling Creek, an elevation
adjustment factor was assumed as 0.003 cfsm per foot increase in elevation. Areal adjustments for basin
size were calculated as a percent of total.
Drainage areas for each basin and associated subbasins were measured from USGS 1:63 360 (1" = 1 mi)
topographic quadrangles, with contour intervals of 100 ft. Elevations and stream channel gradients were
also measured from these maps.
2.3.4 Environmental/Regulatory Evaluation
With the exception of preliminary field studies done for the Old Harbor project as a part of their ongoing
FERC license process, few project -specific data are available regarding the environmental resources of
the areas to be potentially impacted by these project developments. Accordingly, the environmental and
regulatory feasibility of the two projects was evaluated based on information obtained from:
• The general environmental resource literature available through the Alaska Resources Library and
Information Services (ARLIS),
• Environmental reports on the proposed projects prepared by earlier investigators or project
developers,
• Information obtained from interviews with resource agency staff members responsible for the
permitting of these developments including the Alaska Department of Natural Resources (ADNR),
Alaska Department of Fish and Game (ADF&G), U. S. Fish and Wildlife Service (USFWS) and the
National Marine Fisheries Service (NMFS),
j Land ownership and land status information obtained from U. S. Bureau of Land Management (BLM),
ADNR records, and City/Village officials,
• Interviews with local officials and knowledgeable residents in both communities, and
• Field observations of environmental resource conditions of the general project areas during the
Phase II field reconnaissance.
Using the information obtained from the above, project environmental viability was assessed by first
identifying conditions which might be considered environmental "fatal flaws" and attempts to determine the
likelihood that such conditions might exist in the project development areas. Potential presence of
threatened or endangered species and/or critical habitat areas (including extensive anadromous fish
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ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
spawning and rearing habitat) or existence of significant cultural resources within areas where project
development would obviously have impacts, as well as existence of restrictive land use/ownership status,
were used as possible fatal flaw conditions. Where such conditions were found to potentially occur, the
proposed development was evaluated to determine if it was likely to impact these conditions.
2.3.5 Financial/Economic Evaluation
The project economist collected additional data from AVEC, the City of Unalaska, and previous analyses
in order to refine the assumptions about the diesel systems, staffing levels with and without hydropower,
and financing parameters.
The economic evaluation model used in the Phase I evaluation has been employed in this (Phase II)
-� evaluation. Because there is reasonable certainty about construction cost, hydropower maintenance cost,
and interest rates, the number of critical assumptions with probabilities attached has been reduced to two
(load growth and fuel price) for Old Harbor and one (fuel price) for Unalaska.
1 The Phase I model has also been extended to perform a utility financial analysis that determines projected
lJ changes in actual nominal dollar revenue requirements through time for the utility system with and without
the hydropower projects. The basic assumption is that the projects would be 100% debt financed. For Old
Harbor the financial analysis considers the entire AVEC system, since the costs and benefits of such
projects would be spread over all AVEC members.
y Changes to Modeling Strategy. The treatment of nonfuel operations and maintenance (O&M) for both
It diesel and hydropower has changed since the Phase I analysis. On the diesel side, the most important
change is the treatment of diesel overhaul costs. In Phase I, these costs were calculated based on the
number of hours that the diesel units are on. For this (Phase II) analysis, we assume that essentially all
overhaul costs are avoided by the hydropower project in Old Harbor, and essentially none are avoided in
Unalaska.
The reason for the change of method in Old Harbor is that using a reasonable per -hour overhaul cost
calculated from engineering estimates seems to greatly understate the actual documented total amount of
nonfuel O&M. Since the diesels would be effectively turned off in Old Harbor, it makes sense to use the
actual data on the total cost of nonfuel O&M to come up with a fixed amount that is simply avoided by
hydroelectric development. In Unalaska, however, it is unlikely that the small amount of hydroelectric
energy (relative to total diesel output) will result in any reduction in diesel overhaul costs.
On the hydroelectric development side, the project team refined our maintenance cost estimates for the
hydropower system into specific line items. This allowed an ability to isolate the portion of hydropower
O&M expense that is additional to the routine maintenance that could be assigned (at zero incremental
cost) to the existing operator. The result of this exercise is an estimate that for Old Harbor, the total
nonfuel power production expense is about $13,000 lower with hydropower than without. In Unalaska, no
overhauls are avoided, but more skilled labor would reduce the need for imported skilled labor to maintain
the hydropower. Considering both of these factors and applying them to the Old Harbor case, I arrive at an
assumed value of zero for the net O&M due to hydropower in Unalaska.
2.4 ACKNOWLEDGMENTS
The Locher team has received valuable input from many agencies and private individuals. From the City
of Unalaska, information was provided by Mike Golat, Director of Public Utilities, and Karen Blue,
Environmental Coordinator. Additional information on City water supply and electrical distribution of the
existing systems was provided by Clint Huiling and Bryan Amber.
LOCHER INTERESTS, LTD. PAGE 2.6 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
From the village of Old Harbor, Mayor Rick Berns and Vice -Mayor Jim Nestic, along with Sven Haakinson,
AVEC Board of Directors, and Emil Christiansen, President of Old Harbor Village Corporation, met with
the Locher team to provide additional information on existing facilities as well as background and input
regarding previous hydroelectric power studies. Earle Ausman and Dan Hertrich of Polarconsult provided
copies of existing reports and preliminary survey work done on the Old Harbor Project, along with valuable
insight into local conditions as they affect the design concept as originally conceived by Polarconsult.
Power Cost Equalization statistics for both Old Harbor and Unalaska were provided by Irene Tomory,
DCRA. Existing hydrologic data and personal field observations were provided by Stan Carrick and Roy
Ireland, DNR Hydrologists, as they have visited both project watersheds frequently over the past few
years.
LOCHER INTERESTS, LTD. PAGE 2.7 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
3.0 OLD HARBOR
3.1 LOCATION
The Old Harbor Project is located outside of the community of Old Harbor, on the southeastern coast of
Kodiak Island, approximately 70 mi southwest of the City of Kodiak and 320 mi southwest of Anchorage.
As planned, the project includes a diversion from the upper portion of an unnamed stream (denoted herein
as Balling Creek), draining into Barling Bay southwest of town, with a penstock diverting water to a
powerhouse located on a separate stream (denoted herein as Lagoon Creek) which empties into
Sitkalidak Straight within the borders of the community of Old Harbor (Exhibit Al).
3.2 GENERAL DESCRIPTION OF THE AREA
Exhibit A2 provides the location of the proposed Old Harbor Hydroelectric Projects near the village of Old
Harbor on Kodiak Island.
3.2.1 Kodiak Island
Kodiak Island, along with Afognak, Shuyak, Marmot, Sitkalidak, Raspberry, Sitkinak and Tugidak Islands,
form the Kodiak Archipelago, an extension of the mountainous Kenai Peninsula to the northeast. A
product of tectonic action along the Aleutian Megathrust, Kodiak Island is characterized by inland peaks
rising to as much as 4,470 ft above sea level, with an extensive system of deep bays and fjords, produced
by past glaciation, along the coastal zone. With a total area of approximately 3,600 sq mi, approximately
75% of the Island, including much of the area surrounding Old Harbor, is part of the Kodiak National
Wildlife Refuge (KNWR), world renown for its population of the massive Kodiak brown bear. Kodiak Island
is dominated by a marine climate, with cool summers and relatively warm winters. Temperatures range
from 24 to 60 degrees Fahrenheit (OF) and average annual precipitation is 60 in.
Figure 3.1 - Kodiak temperature.
Annualmeann mun(red)mree ean(gn)ardmean
min. Mn (Clue) Wrperalvea far Kodiak, AMdtt
m 50
�40
g
30
1900 1920 199D 186D 1980 2000
Year
Figure 3.2 - Kodiak precipitation.
Average Monthly Precipitation for Kodiak 1922-1996
N iVe+limr l oMmNbAwn9.
r _ FMdbn elAnm,M Mm.yAvera9e
(soa M)
e +
e +
z
e
Jw Much M" J* Seplemaer NowmDn
F&„ AO Ju,a Auauai Odeaer OeemMer
Mw,p
With an average annual monthly precipitation of 5.06 in, maximum precipitation is received in the fall
(October, 136% of annual average) and minimum precipitation is received in the spring (March, 78% of
annual average) at the northeast region of the Island with fairly constant precipitation year-round. NWS
records indicate that precipitation tends to increase further south along the Island, toward the project site.
3.2.2 Village of Old Harbor
Old Harbor, a federally recognized native community, is located about 70 mi southwest of the City of
Kodiak at 57e15' North latitude, 153e15' West longitude. One of six native communities located on the
LOCHER INTERESTS, LTD. PAGE 3.1 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
I Kodiak Archipelago, it lies on the inner shore of Sitkalidak Straight, separated by less than one mile from
Sitkalidak Island.
3.2.2.1 Population
The site of the first Russian colony in Alaska, the current population of Old Harbor is about 315.
Approximately 89% of the residents are Native, many working as commercial fishers and/or practicing a
traditional Sugpiaq Eskimo culture and subsistence lifestyle. The population of Old Harbor has remained
essentially flat over the last 15 years. A 1982 feasibility report for hydroelectric development in Old Harbor
(Dowl Engineers, 1982) reported a population of about 350, slightly above what it is today. Table 3.1
below provides population data for the period 1990 through 1996. As shown, growth has been slow since
1990.
Table 3.1 - Alaska Department of Labor Population Data for Old Harbor, Alaska.
3.2.2.2 Economic Base
Fishing provides the major source of income in the community, but like many other small rural Alaskan
communities, unemployment is high (39.1 % at the time of the 1990 U.S. Census). At the time of the 1990
census, the median household income was $16,875 and approximately 32% of the residents were living
below the poverty level.
In 1997, 35 commercial fishing licenses were issued, indicating the efficacy of the local fishing industry. In
addition to commercial fishing, tourism is of increasing importance to the local economy. The Sitkalidak
Lodge, located in Old Harbor, provides modern accommodations and guide services for visitors to the
area interested in fishing and ecotourism. Likewise, a bed and breakfast facility is now under construction
near the airport.
Old Harbor is accessible by air and water. A new 2,000-ft runway was completed by the State in 1993.
Currently, two carriers both provide regular (twice daily) air service from Kodiak City, Monday through
Saturday with one flight each on Sunday. Both Seattle -based and local barge services are available,
although trips are not scheduled on a fixed basis but rather made as operators accumulate sufficient loads
for Old Harbor and other communities in the area. Generally, about two Seattle -based barges arrive per
year. The harbor provides docking facilities for 55 boats.
Old Harbor completed construction of a new school (K-12) in 1988 which is currently attended by
approximately 90 students. Old Harbor Health Clinic and the Old Harbor Village Response Team provide
health care and emergency services to the community.
3.3 EXISTING POWER SYSTEM
Electric power is provided by the Alaska Village Electric Cooperative, Inc. (AVEC), an organization
currently providing electric power to 50+ rural communities throughout Alaska.
LOCHER INTERESTS, LTD. PAGE 3.2 JANUARY 09, 1998
I
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
3.3.1 Installed Capacity
Old Harbor has a total installed capacity of 200 kW. The present system consists of two 75 kW Caterpillar
l and one 50 kW Cummins diesel generators. The 50 kW unit is the newest of the three and is
preferentially used.
3.3.2 System Loads
The Old Harbor utility currently serves 121 customers, including 98 residential, 12 commercial, 10
! community, and 1 government consumer. Residential users comprise the bulk of the system load,
1 accounting for 55% of the power sold in fiscal year 1997. Of the remaining sales, 27% were to
commercial users, 18% to community facilities, and 1 % to State and Federal facilities.
I
i
3.3.2.1 Annual Generation
Statistical reports for fiscal years 1992 through 1997 (July, 1991 through June, 1997) indicate an average
annual generation of 727,372 kilowatt hours (kWh).
Table 3.2 - Old Harbor Annual Generation and Power Sold for Fiscal Years 1992 -1997.
Generated (kWh)
683,000 1
734,000
724,000 747,000 1 743,000
733,000
Percent Change
n/a
+ 7.5
- 1.4 + 3.2 - 0.5
- 1.3
Sold (kWh)
602,000
646,000
645,000 669,000 671,000
660,000
Percent Change
n/a
+ 7.3
- 0.1 + 3.7 k + 0.3
-1.6
As shown, annual loads and power sold have remained essentially flat over the past five years.
PCE filings for fiscal year 1996 indicate that station service consumes approximately 4.8% of the power
produced while line losses equal about 5.1%.
3.3.2.2 Average Monthly Generation
As shown in Figure 3.3 below, Old Harbor exhibits a winter peak in average monthly energy use, with
monthly averages over the past five years ranging from a high of 70,166 kWh in January to a low of
46,498 kWh in June.
LOCHER INTERESTS, LTD. PAGE 3.3 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Figure 3.3 - Average monthly power generation for Old Harbor.
Old Harbor, Average monthly generation in kWh; Fiscal years 1992-1997
70000
ea000 ;
i
50000
a0000
3 i
Y
30DOO1
10000
of
jan feb mar apr may Jun jul au9 sep act n0V dw
Month
3.3.3.3 Peak Loads
For the period of July 1992 through June of 1997, monthly peak demands on the Old Harbor system, as
reported to the DOE in monthly Power Cost Equalization (PCE) program filings, have ranged from a low of
95 kW in July (1992 and 1997) to a high of 195 kW in September (1997).
Table 3.3 - Old Harbor system peak demand (kW) by month for 1992 -1997.
January
n/a
155
164
164
155
155
February
n/a
155
146
146
146
138
March
n/a
155
146
146
138
138
April
n/a
147
146
138
146
138
May
n/a
138
138
138
129
138
June
n/a
112
103
129
120
146
July
95
121
112
104
112
95
August
112
130
120
138
129
103
September
138
38
146
138
195
October
147
138
146
n/a
November
155
q147146
72
146
146
n/a
December
147
64
164
155
n/a
LOCHER INTERESTS, LTD. PAGE 3.4 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
3.4 HYDROELECTRIC DEVELOPMENT ALTERNATIVES
There have been a number of investigations into the feasibility of developing the hydroelectric potential in
and around Old Harbor over the past twenty years. These include a study prepared for the Alaska Power
Administration (AVEC, 1979), a study done for the U.S. Army Corps of Engineers (Ebasco Services, 1980)
and one completed for the Alaska Power Authority (CH2M-Hill, 1981). A fourth study, also funded by the
Alaska Power Authority (Dowl Engineers, 1982), reviewed and updated the conclusions of the three earlier
investigations and is the main source for the discussion presented below.
As shown in Table 3.4 below, six potential developments were evaluated in the 1982 Dowl report. These
included most of sites evaluated by the three earlier investigations, as well as new developments not
previously identified. This table summarizes the characteristics of the various sites evaluated. The
location of each is shown in Exhibit A2.
Table 3.4 - Alternative Old Harbor Hydroelectric Developments (Dowl, 1982).
Ohiouzuk Creek 1
1.7
8.1
250
3900
0.9
125
Ohiouzuk Creek 2
1.8
8.6
155
3000
0.9
80
Midway Creek.
2.2
10.5
295
2200
3.0
340
Barling Bay Tributary
4.6
26.0
340
5200
1.6
490
Upper Big Creek
5.4
54.0
410
4500
6.2
1400
Big Creek Tributary
0.4
2.4
820
2400
3.3
130
As detailed in the Methods section of this report (Section 2), the Locher team has reviewed the contents of
the above cited reports. During the field reconnaissance of the selected Old Harbor development, the
team completed a helicopter flyover of each of the alternative sites listed above to confirm, first hand, the
conditions cited by Dowl (1982) as reasons for rejecting or selecting each site for potential development.
3.4.1 Ohlouzuk Creek
Ohiouzuk Creek, located less than one mile southwest of Old Harbor was the first drainage recommended
for hydroelectric power development (Ebasco Services, 1980; CH2M-Hill, 1981). Although located close to
town, the small drainage area and attendant reduction in flow reliability, along with geotechnical concerns
which could negatively affect construction costs in this deep canyon (cut through weathered siltstone),
were cited by Dowl (1982) as reasons for rejecting both Ohiouzuk sites.
During Locher's reconnaissance, it was confirmed that the problems cited by Dow[ appear significant. In
addition, it was noted that, while the stream itself is close to the older section of Old Harbor, access to the
site could require full -bench road construction into a steep hillside.
3.4.2 Midway Creek
This site, located near the head of Midway Bay across from the newer section of Old Harbor, was the site
selected by Dowl (1981) for development. Ease of construction of the penstock and a diversion dam site
that would lend itself to future expansion to allow storage, thus providing additional energy when needed,
were reasons cited by Dowl for favoring development of the Midway Creek site. Only the length of the
transmission line and access road (3.0 mi) were identified as possible constraints to development of this
site.
LOCHER INTERESTS, LTD. PAGE 3.5 JANUARY 09, 1993
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
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Locher concurs with the finding that the access road and transmission line would be more costly than for
most of the other projects. Additionally, while this site has a slightly larger drainage basin (2.2 sq mi), it
has a much lower gross head (295 ft) than does the Barling Creek site selected by Polarconsult (1.7 sq mi
and 747 ft respectively, see details below).
3.4.3 Barling Bay Tributary/Barling Creek
This site includes a diversion below the confluence of the East and West Forks of Barling Creek. This
arrangement allows capture of flows from the entire 4.5 sq mi of the upper Barling Creek Basin with
diversion to a powerhouse on Lagoon Creek. In the Dowl report (1982), development of this transbasin
diversion was eliminated from consideration due to the construction requirement of a trench 50+ ft in depth
through the divide between Barling and Lagoon creeks, in order to reach the powerhouse.
I Locher's field reconnaissance confirmed that the cost of excavating to place the penstock through the
bench between the Barling and Lagoon creek drainages would be expensive, and given the location of this
site within the KNWR, its development could be more difficult from a regulatory/environmental permitting
perspective as it would entail extensive excavation on refuge land.
3.4.4 Big Creek
This site, located in upper Big Creek about seven miles north of Old Harbor, would support development
of a project with approximately 1,400 kW of installed capacity, far in excess of Old Harbor's requirements.
Excess size, combined with the long distance required for an access road and transmission line were cited
by Dowi (1982) as reasons for rejecting this site.
Based on Locher's reconnaissance, it is clear that based on size and cost considerations, this site is
inappropriate for development, at least in the foreseeable future. Moreover, given its location in the
KNWR, a project of this size is not likely to be easily developed.
3.4.5 Big Creek Tributary
This site, located two miles northwest of the Midway Creek site, is located on a short, very steep drainage
with two small perched lakes in the upper portion of the basin. Potential problems with water availability
from this very small basin (0.4 sq mi), distance from Old Harbor, and possible construction difficulty were
cited by Dowl as reasons to eliminate this site.
During Locher's flyover of this site, significant portions of the stream were dry, lending credence to the
concerns for reliability of the water supply, given the small size and extremely steep slope of this drainage.
3.5 SELECTED ALTERNATIVE
AVEC commissioned a feasibility study of hydroelectric power development for Old Harbor (Polarconsult,
1995) which resulted in the selection of a variation on the Barling Bay Tributary development first
evaluated by Dowl (1982). Polarconsult's selected alternative proposes a diversion located on the East
Fork of Barling Creek above its confluence with the West Fork, at an elevation of about 830 ft. As in the
case of the Barling Bay Tributary alternative considered by Dow], the diversion is intended to provide
j water to a powerhouse located on Lagoon Creek, at an elevation of about 80 ft. Water would be
j conveyed to the powerhouse via approximately 3,300 ft of 16-in diameter High Density Polyethylene Pipe
(HOPE) in the upper section and about 7,000 ft of 16-in steel pipe in a lower, high pressure penstock
section. Exhibit A3 provides the location of the proposed project.
LOCHER INTERESTS, LTD. PAGE 3.6 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
The Polarconsult concept differs from the original Barling Creek project evaluated by Dowl (see
subsection 3.4.3 above) in that it proposes that the diversion structure be located at a higher elevation,
thus avoiding the necessity of extensive excavation across the drainage divide for the penstock (although
the total length of penstock is greater). Voxland (1995) evaluated a similar concept but proposed
installation of a larger unit (600 kW) than that recommended by Polarconsult (see below).
Based on the site characteristics as summarized in Table 3.5 below, Polarconsult proposes installation of
a single 330 kW impulse unit capable of producing approximately 2,665,000 kWh of energy per year
(about 3.7 times Old Harbor's current use).
Table 3.5 - Project Data for Polarconsult Barling Creek Project (Polarconsult, 1995).
Diversion Height
e 9 A
4 ft j
Intake Elevation
830 ft msl
Powerhouse Elevation
80 ft msl
Installed Capacity
330 kW
Number of Units
1
Type of Turbine
Impulse
Basin Area
1.8 sq mi
Average Annual energy
2,665,000 kWh
Design Flow
7.5 cfs
Gross Head
747 ft
Design Head
678 ft
HDPE Inside Diameter
13.9 in
Steel Penstock Inside Diameter
15.7 in
HDPE Pipe Length
3,293 ft
Steel Penstock Length
6,966 ft
Transmission Line to Pumphouse Length
4,375 ft
3.5.1 Project Location
As shown in Exhibit A3, the proposed project intake and diversion site would be located on the East Fork
of Barling Creek, 3.3 mi north-northwest of Old Harbor. Water would be conveyed to a powerhouse
located on Lagoon Creek, upstream of the existing pumphouse, via a penstock 10,300 ft in length. As
currently planned, the penstock would be routed from the diversion towards the east-southeast for
approximately 7,500 ft before heading in a more southerly direction along the left bank of Lagoon Creek.
The powerhouse is planned to be located on the left bank of Lagoon Creek, about 20 ft above the creek
bed and near the point where the creek emerges from the gorge onto an alluvial fan. Presently, the
transmission line, planned to tie into the existing transmission system at the city pumphouse located 4,375
ft downstream, is to be routed along the right bank of Lagoon Creek.
Locher generally concurs with Polarconsult's selection of this site as the most appropriate for Old Harbor,
and it is this development which is evaluated in more detail below.
3.5.2 Current Project Development Status
Following completion of the feasibility report identifying the East Fork Barling Creek development as the
preferred alternative (Polarconsult, 1995), AVEC filed an application for a preliminary permit with the
Federal Energy Regulatory Commission (FERC). This application, filed in October of 1995, resulted in the
issuance of a preliminary permit on March 11, 1996. The preliminary permit was issued for a period of 36
LUL;Ht_R INTERESTS, LTD. PAGE 3.7 JANUARY 09, 1998
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ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
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months (through March, 1999) or until a development application is submitted by the applicant. AVEC has
elected to pursue the relatively recent Applicant Prepared Environmental Assessment (APEA) procedure
and is currently conducting initial studies and completing the agency consultation process to define the
details of the procedures to be followed in their preparation of a Draft Environmental Assessment (DEA),
for submittal to FERC in support of their license application. The schedule developed for this process
calls for submittal of the DEA in the last quarter of 1998, with a FERC licensing decision estimated to
follow in mid-1999. As required by the preliminary permit, AVEC has filed progress reports with the FERC,
including two recent reports which include the results of preliminary field studies of the terrestrial, aquatic.
and cultural resources in the area (AVEC, 1997a, 1997b)
Assuming their schedule for completion of the APEA is realistic, and that no environmental/regulatory
issues are identified which might result in delay with FERC action, project construction could begin in 1999
and the project could be on-line in year 2000.
'_' 3.5.3 Topography/Drainage Basins
Old Harbor lies on the inner shore of Sitkadilak Straight, backed by the rugged, steeply rising slopes of the
Kodiak Range. The mountains immediately inland of Old Harbor exceed 3,000 ft in elevation within 3 mi,
and the only remaining glacier on Kodiak Island is visible to the northeast of the town at elevation 4080.
Due to rugged topography, streams tend to have steep gradients throughout much of their lengths, and
rapids and waterfalls often isolate fish populations from significant portions of the upper basins, even in
shorter streams draining directly into the ocean. Salmonid habitat is commonly restricted to lower portions
of the streams, and, in general the coastal and nearshore marine environment comprises the most
productive and biologically diverse habitat available.
j Two short, small streams drain the area immediately surrounding the town, Ohiouzuk Creek to the
J southwest and Lagoon Creek to the northeast. Larger drainages include Big Creek which drains into
Midway Bay and a complex of streams draining into Barling Bay, including the stream designated herein
I as Barling Creek (Exhibit A2).
As shown in Exhibit Al, Barling Creek has a total drainage area of approximately 7.75 sq mi. The East
i Fork of Bading Creek, site of the proposed diversion for the hydroelectric project, drains an area of
approximately 2.1 sq mi, with the area above the proposed diversion site encompassing about 1.7 sq mi.
The creek heads near elevation 1900 and joins North Fork Barling Creek at confluence elevation 480 ft.
3.5.4 Geology/Soils
Geologically, Kodiak Island is an extension of the Kenai Peninsula, from which it is separated by nearly 40
mi of salt water. Like the Kenai Peninsula, Kodiak Island consists mainly of accreted materials: mainly
marine sedimentary lithology (shales and graywackes), deformed and metamorphosed to varying
degrees. Soils are virtually all formed from or over volcanic ash (USFWS, 1987).
Bedrock is not evident at the location of the proposed diversion site, along the penstock route, or at the
powerhouse site. It is assumed that rock is at such a depth as to not affect construction. The creek bed is
comprised of gravel and small to medium sized stones. The proposed penstock will require shallow
trenching, probably encountering fine grained soils and occasional large stones. The same condition can
be expected at the bench on which the powerhouse is proposed to be constructed.
LOCHER INTERESTS, LTD. PAGE 3.8 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
3.5.5 Hydrology
As proposed, the project will utilize runoff from a 1.73 sq mi drainage area supplying the upper East Fork
Barling Creek drainage. The basin is approximately 1 mi wide and dissected by the south -flowing creek
flanked by basin -divide elevations of approximately 3200 ft on the west, 1600 ft on the east, and 2800 ft to
the north with side slope gradients ranging from 30-50%. The area's rugged terrain causes considerable
temporal and geographical variations in precipitation and temperature. The East Fork descends 440 feet
per mile (ft/mi) in a trapezoidal channel, with medium to large rock substrate present and encroaching
vegetation. The basin is free of lakes and glaciers. Approximately 3 mi downstream of the gage site,
I Barling Creek flows into Barling Bay two mi southwest of Old Harbor.
The climate of the project area is largely maritime with occasional movements of continental air masses
controlled by the Japan Current that sweeps through the Gulf of Alaska. Therefore, the climate is mild and
generally uniform, with cool summers, mild winters, and moderate to heavy precipitation well distributed
throughout the year. Though the watershed is rain dominated, snow does accumulate on north -facing
slopes at higher elevations (>800 ft) throughout the winter. Snowpack persists through early summer,
with melt -augmented flows.
3.5.6.1 Existing Data
Limited precipitation records have been measured near the basin. From November 1968 to June 1971,
precipitation was recorded, intermittently, in Old Harbor by the NWS; nearly complete monthly average
precipitation records exist for only the years 1969 and 1970. The closest precipitation gage to the site
with a longer period of record is that of Shearwater Bay, 20 mi to the northeast on Sitkalidak Strait at
Kiliuda Bay, with data from January 1952 through February 1964. At Kodiak City, precipitation data has
been collected on a monthly basis since 1922 providing nearly a 75-year period -of -record.
For the two nearly complete years of data measured at Old Harbor, the reported precipitation was 26.6
inches in 1969 and 58.0 inches in 1970. The reported precipitation in Kodiak for these two years was 69.7
and 55.6 in, respectively. However, the long-term (1922-present) average annual precipitation at Kodiak
is 60.7 in, indicating that 1969 and 1970 received nearly average precipitation. The mean annual
precipitation for Old Harbor has previously been reported near 80 in, which indicates the years of record
were below average and possibly suspect. Due to the lack of precipitation information obtained at the Old
Harbor site, the measured data and its correlation with longer local records is inconclusive.
Figure 3.4 - Average monthly precipitation measured at Kodiak and Old Harbor gaging sites.
Average Monthly Precipitation
i
20
16
i6
.. 14 .. �Okl Wrbor
12 _ —Kodiak
9 /0- - .. 0.Y. average On Wreor
a _ .0.Year average Kadbk
n 6.
z
0
w - - - g - - w - _ g - - - a -
-.
Month of Record
LOCHER INTERESTS, LTD. PAGE 3.9 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
The project site should receive greater precipitation than that measured near Kodiak. A 2000 to 4000 ft
mountain range extends southwest across Kodiak Island, 8 mi inland from Old Harbor, which has a
predominant effect on precipitation patterns across the island as moist air on the windward side is uplifted.
The windward side of the orographic barrier should receive more precipitation. It has been reported that
precipitation tends to decrease across Kodiak Island from the southeast (near Old Harbor) to the
northwest. A comparison of precipitation data measured at Shearwater Bay indicates this effect (Figure
3.5). For overlapping periods (1952-1964) for these two stations, precipitation data is highly correlated (r
= 0.80) across the east island coast. For this 13-yr record, the Kodiak precipitation gage recorded an
average annual measurement of 52.8 in precipitation, or 87% of the 75-yr mean. For complete data years
during the same period of record, the average annual precipitation measured at Shearwater Bay was
106.4 in. If this was also assumed to be 87% of normal for a similar 75-yr historical record, the long-term
precipitation received at Shearwater Bay could be assumed even greater.
Figure 3.6 -Average monthly precipitation measured at Shearwater Bay and Kodiak gaging sites.
Average Monthly Precipitation 1952-1964
Shearw ater Bay
35
r
_ - - - Kodiak W
30
j
—13-year average at Shearw ater
--�.
25
- .-13-yearaverageat Kodak
k
1
20
15-
I
n
5
s f �,
i 1— n• 'y� I r• 1
f �� J �1 1 1 I, ✓� •.. :" d- .
•IV
N
N .
N
N N N YI b ,Oq 0 0 � 1`
N
n Itl 0 O, O) .O � O
N y, N N N N dl
� m
0..
b
(7 <`
fp N ip T
O
d d b A t� q O/
L 7 df A
W
C'
O 6' m
Z
Q
'
l .'
N LL ❑❑ a! a l
D16
Z Q N LL ❑ i; ❑
..JJ
Q N LL ❑
Month of Pacord
I Using linear regression, precipitation at Shearwater Bay ("y") can be loosely described in terms of
precipitation at Kodiak ("x") by the equation y = 0.34x + 80.25 (R2 = 0.49). Due to the low R2 predictive
...� value, historical precipitation records measured over the longer period of time at Kodiak were used in
hydrology calculations herein. That is, percent deviation from normal precipitation measured at Kodiak
1 was applied to gaged streamflow to approximate deviation from normal water yield at Old Harbor.
{ The closest long-term stream gage near the project area was operated by USGS on the Upper Thumb
i River, 24 mi northwest of Old Harbor, from 1974-1982. During the period of record, the 18.8 sq mi basin
experienced an average annual discharge of 92 cfs, for a unit discharge of 4.9 cfsm. This basin is on the
leeward side of the orographic barrier, and as expected receives less precipitation than the project area.
Additionally, 5 years of gaged data have been recorded for nearby Midway Creek from 1982 through
1986. This gage was managed by Dowl Engineers at a stream 3.5 mi northeast of the village of Old
Harbor. The drainage area to the gage site was 2.28 sq mi. As reported, unit discharge during the period
of record for this basin was 7.29 cfsm, with a mean annual discharge of approximately 16 cfs.
Daily streamflow data were recorded at the Barling Creek confluence from 1993 to 1996 by DNR. More
recently, a second gage was installed near the diversion site. This second gaging station has recorded
stage, with minimal velocity readings to correlate with various water surface heights. Thus, few discharge
measurements have been calculated to develop an accurate or usable rating curve. This second gage is
still in operation and is currently being maintained by Polarconsult, but few trips have been made to the
field to download data.
I
LOCHER INTERESTS, LTD. PAGE 3.10 JANUARY 09, 1998
t
I
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Based upon limited stream discharge and local precipitation data available, average daily discharges for
the proposed project were obtained by adjusting the gaged streamflow data. The discharge data were
adjusted for long-term climatological effects using precipitation data as measured at Kodiak with the
multipliers in Table 3.6 below. Multipliers below 1 indicate an average annual precipitation above normal;
for the year 1996, the multiplier is above 1, indicating a drought year. After adjusting water yields based
upon long-term climate trends, the streamflow data collected at the confluence gage were adjusted for the
project area by both drainage size and elevation to obtain average daily discharge values at the diversion
site for input into the energy model.
Table 3.6 - Multipliers used to adjust gaged stream data for Barling Creek.
Average Annual Precipitation at
Kodiak (in)
60.7
78.9
83.9
95.3
56.4
Percent of 75-year mean
1.00
1.30
1.38
1.57
0.93
Factor used to adjust daily
stream discharge
1
0.77
0.72
0.64
1.07
Using the 4 years of adjusted gaged data, the daily means and standard deviations were calculated and
used to stochastically generate a 10-year simulated dataset of 365 synthetic daily averages at the project
site.
3.5.5.2 Assumptions
An elevation adjustment factor of 0.003 cfs per square mile (cfsm) for each foot of additional basin
elevation was used to account for the effect of height above sea level on increased precipitation.
Runoff calculations account for basin size and elevation, but do not consider temporal or topographic
effects of exposure and location. Average daily streamflow also assumes runoff as a direct function of
monthly precipitation averages and their deviation from a mean, and do not consider local or seasonal
effects (frozen soil, antecedent moisture, senescence, etc.) that may alter water yield following a given
storm event.
3.5.5.3 Predicted Runoff
A hydrograph representing the daily average discharges at the diversion is shown in Figure 3.6; average
monthly inflow is shown in Table 3.7 below.
LOCHER INTERESTS, LTD. PAGE 3.11 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Figure 3.6 - Annual hydrograph showing average daily flows for East Fork Barling Creek.
Old Harbor
East Fork Barling Creek
250
200 .
N
150 -
m 100
r
U
0 50
0
M M M W t0 0a a m m m>> °i n W 0 OU U o o a0i a0i
-� -� IL 2 Q Q o Q Q C? C? OZ Z 0 0
.- (D L6 N ! ." (D (O M V N N N .N- N r N
Date
Table 3.7 - Average monthly flows for East Fork Barling Creek.
tnf low Interval about+
ef
January 15.9 5.8
Design
a -
3.8 31
February
12.9
6.3
3.4
27
March
6.2
1.4
2.2
17
April
11.5
2.6
3.5
28
May
42.7
6.8
13.8
100
June
38.0
3.7
23.5
100
July
47.5
8.8
17.4
100
August
21.4
3.9
9.8
79
September
49.7
14.8
15.3
100
October
34.6
7.5
9.4
100
November
12.2
1.6
5.6
45
December
10.7
2.8
4.0
32
Average Annual
25.3
-
--
-
LOCHER INTERESTS, LTD. PAGE 3.12
JANUARY 09, 199tS
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
11
Given an average annual discharge of 25.3 cfs, the unit discharge expected from the project basin is 12.0
cfsm.
The quantity of water withdrawn is contingent upon demand and would be limited by turbine capacity.
Excess runoff from the basin would pass over the diversion into the natural channel below.
The flow regime is seasonal, with higher flows occurring in May through mid -July from spring snowmelt
and in September and October from rainfall. The stream is perennial, though decreased flows will occur
from December through March. The minimum and maximum recorded daily discharges at the confluence
for the period of record are 0.28 cfs on February 28, 1994 and 895.39 cfs on September 21, 1995, though
DNR hydrologists suspect flows outside the range of 10-150 cfs due to lack of measured data at extreme
ends of the rating curve developed for the stream cross-section at the gage site. Adjusted to the diversion
site, these extremes would represent 0.11 cfs and 358.16 cfs, respectively.
3.5.5.4 Flow Duration Curves
Flow duration computations were calculated for exceedence probabilities for various percentages of the
total days in the record, irrespective of season of occurrence of such flows. The flow duration curve is
shown below (Figure 3.7).
As proposed, the project has a nominal rated and maximum discharge of 12.4 cfs. An inflow of 12.4 cfs
has a probability of exceedence value of 61.6%. The minimum discharge required for power generation
is 1.3 cfs.
Table 3.8 - Average daily discharge associated with a given probability of exceedence value.
1 rc raF ili3y t f
Aveget ilt' flflsct ve
95
3.29
90
4.22
85
5.09
80
6.08
75
7.66
70
9.13
65
10.64
60
13.23
55
15.59
50
17.71
45
20.02
40
24.11
35
26.04
30
30.70
25
34.43
20
38.11
15
42.08
10
54.90
5
78.49
INTERESTS, LTD. PAGE 3.13 JANUARY 09, 1998
I
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
would be installed to allow material to be sluiced back to the creek. The sluice gate would be manually
operated and would be a regular maintenance item, especially after large storm events. The desanding
structure would contain a level control transducer, sending signals to the powerhouse for control of turbine
nozzle openings. As the penstock leaves the desander, it would have adequate submergence to prevent
formation of vortices which would entrain air into the penstock, leading to turbine nozzle damage.
3.5.6.2 Penstock
The penstock is approximately 10,300 ft long, extending from the desanding structure to the powerhouse
located on the left bank of Lagoon Creek. The penstock would be buried along its length. Based on the
geology observed during our. site visit, it would not be expected that much bedrock would be encountered
while trenching for the penstock. However, the true nature of the soil below ground level is unknown. It is
assumed that fine grained materials will be present because the ground surface was noticeably wet in
areas, indicating that the upper soils were not free draining. It is possible that small rocks to larger
boulders may be encountered during excavation. We have assumed that the majority of the material
excavated from the trench may be used for backfill with very little imported fill being required, except for 6-
in of bedding below the pipe. It is expected that the entire penstock could be excavated with a back hoe
with a 2 cubic yard bucket.
We examined penstock diameters for a range of turbine sizes from 300 to 500 kW. Typically, penstock
sizes are optimized taking into account penstock procurement and construction costs, pipe friction
headlosses, and the variation in energy with the subsequent varying net head. Our initial studies, though
not detailed for this phase, indicated that there is not a substantial difference in energy produced for
penstock sizes ranging in diameter from 16 to 24 inches. Therefore, we concur with Polarconsulfs
selection of a 16-in inside diameter penstock. Penstock diameters less than 16-inches did not appear to
be practical.
Several materials may be appropriate to be considered for the penstock pipe, depending on internal
pressure. They include high density polyethylene (HDPE), ductile iron, and steel. The Polarconsult report
indicated that the upper 3,300 ft of penstock would be HDPE and the lower 7,000 ft would be steel. These
materials and overall configuration were used in our studies. The lower portions of the penstock would be
designed for an operating pressure of 325 psi -plus a minor pressure rise, considering a gross head of 750
ft. For the purposes of this report, we assumed that the upper HDPE pipe would be provided in three
different wall thicknesses, varying with increasing pressure, and that 10 gauge steel pipe would be used
for the lower portion. The upper sections of the steel pipe would have bell and spigot, rubber gasketed
joints to a pressure of 300 psi, an epoxy coating on the inside, and tape wrap on the outside. The lowest
portion of the steel pipe, nearer the powerhouse, would have field welded joints, requiring repair of the
internal coating.
The penstock would leave the East Fork Barling Creek drainage from the left bank of the creek and head
southeasterly, crossing the boundary of the drainage into the Lagoon Creek drainage. Polarconsult
performed a survey to verify that the drainage boundary elevation, where the penstock leaves the
drainage, is lower than the point of diversion. The general direction of the penstock is southeasterly along
its entire route to the powerhouse. The penstock would be located on the left bank of Lagoon Creek and
situated on a bench above the creek. The bench is generally sloped toward the creek and downhill toward
the powerhouse. Along its route, the penstock will cross several ravines where side drainages enter
Lagoon Creek. The ravines become deeper and wider the closer they are to the creek. The ravines will
need to be crossed by spanning the pipe and adding crossing structures or, alternately, some ravines may
be avoided by situating the penstock higher up the bench, which would increase the penstock length. The
penstock route has several high and low points along its length. It would be expected that at these points,
air -vacuum valves and blow -off valves would be located for protection and draining of the penstock,
respectively.
LOCHER INTERESTS, LTD. PAGE 3.15 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
3.5.6.3 Powerhouse
The powerhouse would be situated on the left bank of Lagoon Creek at about elevation 80 ft msl, on a
bench approximately 20 ft above the creek. The powerhouse would house the turbine, generator,
controls, switchgear, and station service equipment. The powerhouse should be constructed so as to be
vandal resistant, of the pre-engineered steel type, with heavy steel doors and no windows. The
powerhouse would obtain its power from that generated by the equipment or from the grid, if the plant is
down for service or low flows. The powerhouse would be heated to prevent freezing or condensation, and
ventilated to prevent overheating of the equipment. If desirable, propane space heaters could be provided
in the event of a transmission line outage over an extended period of cold weather.
—� The floor of the powerhouse would be of reinforced concrete, with embedded parts for the turbine and
generator. Below the floor slab, the turbine will exhaust its flow into a flume which conveys water away
from the powerhouse. The flume would transition to a corrugated metal pipe to convey water down to the
creek. Where water enters the creek, about 20 ft below the powerhouse, the energy in the falling water
will be dissipated by allowing it to flow onto boulders or riprap.
The powerhouse will be unmanned, meaning that the generating equipment will have adequate controls to
allow it to operate and adjust itself without the attendance of an operator. Daily visits to the plant are
prudent to check security and provide routine maintenance. It is possible and prudent to allow remote
control and monitoring of the plant via telephone and modem to the operator's house. Remote monitoring
and control functions will involve the capability for remote starting and stopping of the unit.
" 3.5.6.4 Turbine and Generator
j A 500 kW Pelton, impulse -type turbine would be used for this project. This is substantially larger than that
proposed by Polarconsuit and large for the existing system load. However, this size turbine is reasonable
for the site (see paragraph 3.5.7.1 for a further discussion of turbine sizing). The turbine would have a
steel housing, two jets, and a stainless steel runner about 22-in in diameter. The needles would be motor
actuated by DC power. Depending on supplier, the turbine/generator shaft will be horizontal or vertically
oriented.
The generator will be a 480 volt AC synchronous type with brushless exciter, 0.9 power factor, and an
allowable temperature rise of 800C over 400C ambient_ The controls would allow local manual or
automatic operation of the generating unit.
3.5.6.5 Switchyard and Transmission Line
The substation would consist of a pad mounted transformer, cable connections to the generator circuit
breaker and the overhead transmission line, and a grounding grid. The oil filled, pad -mount type
transformer would be rated for 750 kVA and include internal primary fuses and switch. The transformer
would step up the 480 volt, 3-phase generator output to the required 12,470 volt, 3-phase transmission
line voltage (assumed). The generator circuit breaker would be cable connected to the low side of the
transformer_ The high side of the transformer would be connected to the overhead transmission line with
an underground routed cable. The transmission line termination would be through a gang operated
disconnect switch. Surge arresters would also be furnished at the transmission line termination for
protection of the cable connection and transformer. A copper ground grid would be installed around the
transformer pad and tied into the powerhouse grounding system.
The overhead transmission line (T-line) would connect the power plant substation to the existing
distribution line located near the pumphouse. The T-line would be 3-phase #4 ACSR with solidly
LOCHER INTERESTS, LTD. PAGE 3.16 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
grounded neutral on 30-foot wood poles with standard wood cross -arm construction. The new T-line
would be connected to the existing line through a gang operated isolating switch.
Polarconsult shows the T-line crossing Lagoon Creek at the powerhouse and extending along the right
bank toward the community's potable water well pumphouse. This side of the creek is overgrown with
dense scrub trees and bushes. To construct the line on the right bank would require clearing and heavy
brushing, as well as constructing a construction access road. Our preferred alternative T-line alignment
would extend along the left bank, near or along the access road. Though the total length of the T-line may
be slightly longer and involve several guyed line bends, construction access is already provided and little
or no clearing would be involved.
Typically, for environmental reasons, buried T-lines are desirable to the resource agencies. Above ground
T-lines are prone to impact by raptors and deemed unsightly. However, conversations with community
officials indicated that they have had extremely poor success with underground T-lines and have been
installing overhead lines since_ For this reason, we have included an above ground T-line in this report.
3.5.6.6 Access
Currently, there is no access to the diversion site. A four -wheeler trail extends from the pumphouse to
about halfway up the mountain toward the intake. The remainder of the distance to the diversion site is
unblazed. Access will be required regularly through the operational life of the project. During
construction, it is recommended that a four -wheeler trail be constructed along the upper penstock route so
that vehicle access is possible throughout the year. During the winter, when snow makes four -wheeler
access impractical, snowmobiles can be used. It would be prudent to mark the trail so that it is visible
during heavy snowfall.
Access to the powerhouse during construction would require that the existing four -wheeler trail be
upgraded for about 4,150 ft from the pumphouse. Essentially, this would require widening of the road to
allow pickups and flatbeds to access the powerhouse. Since construction will be performed during the
summer, it is not expected that the road would be graveled, except in areas which require improved
bedding. We assume that beach gravel could be excavated and used in these limited areas. For
permanent access, the construction access road would not be maintained, but four -wheeler or snow
mobile access would be sufficient for personnel, small tools, and consumables.
3.5.7 Energy and Capacity
As explained in paragraph 2.4.1, a computer model was developed to compute average monthly and
annual energy produced by a theoretical project installation. The specific input values used to compute
energy include average daily flows (365 data points), gross head, penstock size, estimated water system
conveyance loss coefficients, selected turbine capacity, estimated turbine operating range(s) and
efficiency curves, and estimated generator and transformer efficiencies. Results of the model output
follow.
3.5.7.1 Installed Capacity
In sizing the unit, turbine sizes from 200 to 6,000 kW were examined, with an increasing annual energy
output computed as the size increased, with the total installed capacity being limited by the penstock size
(see Figure 3.8 below). The Polarconsult (1995) report sized the unit at 330 kW. Another report and cost
estimate by Voxland (1996) indicated that up to 800 kW is possible. By increasing the penstock size, we
found that a unit up to 3,500 kW is optimal with a 36-in penstock, generating 270% more energy than a
500 kW unit.
LOCHER INTERESTS, LTD. PAGE 3.17 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
The peak demand during the past five years was 195 kW as indicated in Table 3.3, so even Polarconsult's
330 kW is capable of supplying nearly twice the requirements of the community, when generating at full
capacity. We selected a 500 kW unit for consideration in this study to allow for future growth and industry
and to maximize the energy potential from the selected 16-in diameter penstock. There is an incremental
cost of about $80,000 (less than 3% of the estimated total cost for development) associated with the larger
generating equipment. In our opinion, this is a reasonable and justifiable cost to provide for substantial
future load growth.
Figure 3.8 - Annual energy output vs. installed unit size (single unit installations).
10,000,000
9,000,000
8,000,000
7,000,000
6,000,000
5,000,000
n
4,000,000
3,000,000
2,000, 000
1,000,000
Turbine Size vs. Annual Energy Output
---------------- ----ram. -__ . _---- - - - - -"- - - - - - - - - - -
42" Penstock
36" Penstock
_ _ _ _ _ _ _ f _ _ _ _ _ _ 7,_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
I_ _ _ _ _ _ _ _ _ _ _ _ _ -- _ _ _ _ _ _ _ _ _ _ _ _ _ _
1
�- 30" Penstock
-----------------------------------
-------------------
---- ----- ------------------------------------
24" Penstock
---- ----------- -------------------------------------
---F--- - - - - --- - - - - -- -------------------------
--___-_.�__-__
-; -- -- 16",18",20" Penstocks i ___- -___. _------____--
------------7 -- - - - - ----- - - - - -. ----------------
1000 2000 3000 4000 5000 6000
Turbine Size in kW
3.5.7.2 Firm Capacity
In reevaluating the installed capacity and the annual energy produced, mathematically averaged daily
flows were used to synthesize daily flows, which were then used to size generating equipment. This has
the effect of producing an estimate of average annual output that is reasonable for this stage of study, but
` does not account for extreme high and low events seen over a day. To determine firm capacity, monthly
low events (and power produced from the low instantaneous events) need to be compared to monthly
instantaneous requirements. This is beyond the scope of this study. Using average daily flows, we
computed that energy would be generated every day of the year, and a minimum output capacity of 110
kW occurs in March.
As an estimate of firm capacity, it has been determined that instantaneous low flows are approximately
20% less than the recorded average daily flows for nearby streams gaged on Kodiak Island of similar
discharge and drainage area (R. Rickman, personal communication). Based upon the 10-year synthetic
flow analysis assumptions used herein, the minimum average daily flow for the site is 2.25 cfs (in
February),
Eighty percent of this minimum daily average flaw, or 1.8 cfs, provides the best available estimate of the
instantaneous low flow for the project. With a minimum rated capacity of 1.3 cfs, the project would be
capable of producing approximately 85 kW at 1.8 cfs.
LOCHER INTERESTS, LTD. PAGE 3.18 JANUARY 09, 1998
0
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
1
1
3.5.7.3 Average Annual Output
Polarconsult computed an average annual output of 2,664,530 kWh with a 330 kW machine. Our annual
energy computation for a 330 kW plant with the same project features is 2,466,410 kWh, a 7.4%
decrease, even though we used a sfightly higher net head (695 ft vs. 678 ft). The computation of this
report includes estimated efficiencies of not only the turbine, but of the generator and transformer,
assumed constant at 93% and 98%, respectively_ Therefore, the efficiencies and/or the flow hydrograph
Polarconsult used are less conservative than used in this study. By installing a 500 kW unit, we compute
that 3.426,990 kWh of electricity at the line can be generated annually (net capacity of 456 kW). These
computations assumed that energy is generated every day that there is flow capable of operating the
turbine. In reality, the equipment will experience some unplanned outages and will also have routine
planned outages when it is taken off line for annual maintenance. Therefore, it is prudent to reduce the
theoretical annual energy computation by 3 to 5%.
The computer model is capable of reducing the flow used for generation due to requirements for instream
flows. The licensing process is not far enough along to determine if an instream flow will be required from
the diversion. For our studies, we assumed that an instream flow would not be required as there is not yet
evidence of an anadromous or resident fishery in the bypass reach, and there is substantial contributing
inflows downstream of the diversion to maintain fish habitat in the lower section of Barling Creek where
salmon spawning does occur. However, instream flow reservations of 1 and 2 cfs would result in
decreased annual energy outputs by 4.2% and 8.7%, respectively.
3.5.7.4 Average Monthly Output
Based on a 500 kW unit, the following monthly average energies were computed without reduction for
downtime and are indicated in Table 3.9 and Figure 3.9 below:
Table 3.9 - Old Harbor monthly total average generation for a 500 kW installation.
January
241,706
71.3
February
191,482
62.5
March
191,489
56.5
April
249,667
76.1
May
339,046
100.0
June
328,109
100.0
July
339,046
100.0
August
336,510
99.3
September
328,109
100.0
October
336,494
99.2
November
298,560
91.0
December
246,774
72.8
LOCHER INTERESTS, LTD. PAGE 3.19 JANUARY 09, 1998
1
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE It
Figure 3.9 - Old Harbor monthly total average generation for a 500 kW installation.
Old Harbor; Average Monthly Generation in kWh
12,000
10,000
x 8,000 _
-'a 6,000 -
a
IL
a
a' 4,000
d
c
W
2,000
0
LL Q co O Z 0
Month
3.5.8 Quantity Estimates for Development
Project -specific topographic mapping was not available for this site_ Therefore, USGS topographic maps
with 100-foot contour intervals were used. Elevations of the intake and powerhouse sites were taken from
the Polarconsult report and were reviewed and found to be consistent with USGS topographic maps. A
review of the Polarconsult project feature layouts was made, and independent layouts performed, for the
purpose of developing feasibility level quantity estimates. Activity durations were estimated based on
conversations with contractors and using reference materials.
3.5.9 Project Cost Estimate
Cost estimates were prepared estimating costs of labor, materials, equipment, and shipping for each work
item. The intent of this approach was to account for the various labor and productivity rates and to ensure
that shipping costs were adequately accounted for. This makes the appearance of perhaps greater detail
than would normally be warranted for a feasibility level cost estimate. The costs and productivity rates
were based on those found in Mean's estimating guides, adjusted by conversations with contractors
accustomed to working in rural Alaska, and conversations with various suppliers. Lump sum estimated
installed costs were divided into labor, materials, equipment, and shipping based on a reasonable split of
work.
Polarconsult, in their 1995 report, assumed a "Force Account" method of construction with local labor used
to the maximum extent possible, to reduce project costs. They assumed laborers at a cost of $20 per
hour which includes wages and taxes, except for a minimum amount of skilled labor to install and test the
LOCHER INTERESTS, LTD. PAGE 3.20 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE1I
generating unit. We feel that application of such an approach is reasonable, to a degree. However,
experience indicates that it is inevitable that more skilled outside labor will be required for construction of a
hydroelectric power project, and will require the inclusion of transportation costs, per diem, and payment
of prevailing wages for all specialists required.
For this study, two cost estimates were prepared: (1) the first based upon a conventional contractor
constructed project, and (2) the second based upon the judicial use of the force account method. For the
estimate based on conventional contractor construction, prevailing wages, based on State of Alaska's
1111197 Laborers' & Mechanics' Minimum Rates of Pay, were used with multipliers for Workers
Compensation, Social Security taxes, etc., and $70 per day for per diem. For the force account method,
lower wages were used without including benefits and per diem for the local, unskilled laborer positions,
and a skilled worker was placed with each unskilled crew. However, production was assumed to be less
using local unskilled labor than for skilled labor, which is typical for standard contracting methods. For
skilled labor, prevailing wages plus benefits and per diem were used. Labor costs for both skill levels
were factored upwards for Worker's Compensation, Social Security taxes, etc.
Costs for materials were based on that required to purchase them in a competitive market, and $0.08 per
pound was used for barge shipping to the site. For materials such as fabricated steel items, the material
price per pound is the away -from -site fabricated price plus the labor quantity required to install it in the
field.
Generating equipment is available from a variety of sources, many of which are foreign. World money
market rates are constantly changing and the level of quality vary, making pricing subject to constant
fluctuation_ In addition, some vendors are not willing or are financially incapable of guaranteeing their
equipment, as do the major equipment manufacturers. At the time of this report, only two quotations had
been received from what we consider to be fully bonafide manufacturers and one from a small vendor.
Equipment rental was assumed to be 30% higher, due to the added cost for maintenance, and additional
wear and tear in the rugged environment of the project area. Shipping costs were added to equipment
rental costs. It was assumed that two track hoes would be used for the majority of the work, as they can
be used for earthwork required at the dam site, powerhouse, and penstock trenching. A small dozer was
assumed to be used for construction of the access road to the powerhouse.
It was assumed that three separate crews would be required for construction. One crew of four people
were assumed to be required for construction of the penstock. This includes a hoe operator, two laborers
in the trench and one spotter. It was assumed that production would be around 500 If of penstock per
day. The other two crews were assumed to be constructing the intake, powerhouse, and gully crossings.
We believe it would be possible to construct the project in a single construction season of six months.
For the standard contracting method we included costs for contractor overhead, profit, insurance, and
bonding and have increased the construction cost by 25%, which is appropriate for this stage of
development, as preliminary designs and detailed surveys have not been performed. We have included
reasonable costs for project administration, FERC licensing and permitting, engineering, and construction
management. For the force account method, we assume that the community is not trying to make a profit
and bonding will not be required, therefore, those costs have been eliminated.
Polarconsult's 1995 report indicated a total development cost of $1,341,889. If escalated to 1997 dollars
using the Handy -Whitman index, their costs rise to $1,422,403. Voxland's estimate for an 800 kW project
was $3,876,035 in 1995; this escalates to $4,112,086 for 1997 costs for a similar project.
Our cost analysis results in estimated total development costs of $2,580,800 for a force account process
and $3,656,200 for a standard construction process. These estimates are 1.8 times and 2.6 times greater
LOCHER INTERESTS, LTD. PAGE 3.21 JANUARY 09, 1998
1
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE li
than the Polarconsult estimate, escalated to 1997, and reflect different levels of risk reduction. Detailed
cost breakdowns are contained in Appendix All,
A comparison of the cost estimate assumptions utilized herein and those used by Polarconsult is
presented below.
Table 3.10 - Comparisons of cost estimates for the Old Harbor hydroelectric development.
Mobilization
62,800
62,800
Site Camp and Equipment
=
52,600
52,600
Turbine, Generator, Controls
79,928
423,600
198,600
Pipe, Appurtenances,
564,902
778,870
693,615
Trenching
Intake, Diversion
96,127
120,031
106,625
Substation
48,039
49,400
49,400
Transmission Line
52,232
38,819
38,819
Powerhouse
51,737
156,436
148,494
Tailrace
---
30,487
28,646
Access Road
48,389
63,910
63,910
.�
FERC License
84,800
150,000
150,000
Overhead, Profit
---
533,100 (30%)
144,400 (10%)
Insurance, Bonding
-
115,500 (5%)
15,900 (1%)
Administration
89,297 (10%)
151,600 (5%)
125,000 (5%)
Construction
37,100
80,000
96,000
ManagemenIII nspections
Engineering
89,297 (10%)
242,600 (8%)
205,000 (8%)
Contingency
133,945 (15%)
606,400 (25%)
401,000 (25%)
TOTAL
$1,422,403
$3,656,200
$2,580,800
As shown in Table 3.10 above, the Polarconsult cost estimate does not include line items for mobilization
or equipment, tailrace construction, project overhead, or insurance/bonding. Our costs for electro-
mechanical equipment are more than double the cost provided by Polarconsult, and include current price
quotes from appropriate manufacturers. Our force account method provides for a turbine purchased from
a smaller local (northwestern) vendor who supplies equipment without warranty, whereas the conventional
cost estimate includes fully warranted electro-mechanical equipment purchased from a larger and major
manufacturer. The costs shown for powerhouse construction vary considerably: Polarconsulfs estimate
provided line items for powerhouse slab and walls, roof, piping, and appurtenances whereas our cost
estimate includes earthwork, valves, concrete, reinforcement bars, a metal building, miscellaneous metals,
monorail hoist, electrical requirements, and installation of an HVAC system. The difference in allowable
contingencies (15% for Polarconsult vs. 25% for this study) also substantially alter the total costs.
3.5.9.1 Capital Replacement Costs
t For the purpose of establishing an annual budget, a fund should be established to allow for future
unplanned, unscheduled replacement costs. Most routine costs will be paid for under the operations and
maintenance (O&M) budget. Additional unscheduled costs may involve work such as a major turbine
overhaul or a generator rewind. Costs for each could be in the order of $100,000 to $150,000. If it were
assumed that 1.5 events occurred every 25 years, then a simple straight-line replacement cost fund would
require that $9,000 per year be placed in a separate account.
LOCHER INTERESTS, LTD. PAGE 3.22 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
3.5.9.2 Operations and Maintenance Costs
Typically at this stage of planning, O&M costs are based on a factor related to the installed capacity. This
does not always provide accurate costs for small plants. In 1994, HydroVision performed a survey of
plant operators to quantify annual O&M costs. For small, single -unit projects, respondents indicated an
average O&M costs of about $38,000; $41,500 escalated at 3% per year to 1997. If a factor for a remote
location in Alaska is used (estimated at 10 to 20% higher), then a planned O&M expense may be about
$48,000 per year.
3.5.10 Economic and Financial Analysis
F l The economic assessment of the Old Harbor project has been updated using refined assumptions (as
discussed in subsection 2.3.4 above). In addition, a utility financial analysis has been used to determine
the implications under debt financing of the project for the AVEC systemwide cost of service and revenue
requirements. The economic analysis is conducted in real 1997 dollars. The financial analysis is
conducted in nominal or current dollars, assuming 3% inflation.
3.5.10.1 Economic Assumptions
The number of critical assumptions with probabilities attached has been reduced to two because firm
estimates for construction cost, maintenance cost, and cost of capital now exist. This leaves load growth
and fuel prices as the two critical assumptions with probabilities attached to them. Load growth is
important in Old Harbor because the hydropower output greatly exceeds current load during all months of
the year.
Table 3.11 below shows the critical economic assumptions used for the Old Harbor economic analysis.
Table 3.11 - Old Harbor critical economic assumptions.
loin W#T.rW=1
C2: Fuel Price Growth
�
-
�1;�►•Ly
1 1
1 ► .
---
C3: ReaWis=cou nt -Rate
-
�-•�
li�
-
-�-
' • • • •
'•
it 111
• • 111
-
11
RUM
11
In.
001
_ • •
M�11
/1M1
M
3.5.10.2 Financial Assumptions
This analysis assumes that the Alaska Village Electric Cooperative (AVEC) is the project owner. Although
AVEC has substantial customer equity in its capital structure and substantial cash in its asset pool, this
LOCHER INTERESTS, LTD. PAGE 3.23 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
analysis assumes that the Old Harbor project will be financed by debt at 5% (nominal) interest. This
assumption of 100% debt financing is not too critical; if AVEC were to use internal finance the foregone
earnings on its liquid assets would probably also be about 5% under a prudent conservative investment
strategy_
The financial analysis considers AVEC as a single utility. The effects of the Old Harbor hydropower project
are computed for the entire pool of AVEC members and for the financial status of the utility. AVEC makes
no attempt to allocate any expenses other than fuel to particular villages. Revenue requirements are
determined as the cost of service plus an appropriate cushion of net income, or "margin," sufficient to
ensure that a target ratio of (interest expense + margin) divided by (interest expense) is maintained. This
ratio is called the 'Times Interest Earned Ratio" or TIER. For AVEC a target TIER of 2.0 is assumed.
Assumptions about Timing. For purposes of financial and rate impact modeling, the Old Harbor Project
is assumed to have the following timetable:
July, 1998: Obtain funding commitments and begin procurement.
December, 1998: Obtain FERC License.
May, 1999: Commence construction.
January 1, 2000: Commence operation.
The time horizon for the Old Harbor hydropower operation is 2000-2034 (35 years of operation analyzed).
The analysis runs from 1997-2034. To simplify the analysis, I assume that ail debt is issued on January 1,
1999. This implies one full year of interest during construction. To put it another way, the capital outlay is
made on 111199 while the benefits from reduced fuel expenses begin accruing on 111/2000. The economic
analysis is unaffected by the calendar date of the start of the project and the results are expressed in 1997
dollars.
Table 3.12 below summarizes the financial assumptions used for Old Harbor.
Table 3.12 - Old Harbor financial assumptions.
Financial Parameters
—Rate
INominal Debt Interest
o
5.0%
New Debt Issuance Cost
o of face va u
. o
Inflation Rate
4
0
Target TIER Ratio
Plant Additions:
Book Life
Yodebt
o quay
ew iese
o
0
New Hydro
a
a
All other New Plant
100%1
0%
3.5.10.3 Economic Analysis
} Under mid -range assumptions with force account construction cost the project has net economic benefits
of +$775,000. With the same assumptions and contractor construction, the project has negative net
benefits of-$260,000. The most optimistic assumptions (3% load growth, 1.5% real fuel price growth,
force account costs) produce $+2.1 million in net benefits; the most pessimistic (0% load, 0% fuel,
contractor cost) produce-$948,000.
Probability Distribution of Net Benefits. Since we still have two cost estimates (contractor and force
account basis) the results are best summarized by two sets of probability distributions, one for each
LOCHER INTERESTS, LTD. PAGE 3.24 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE li
construction cost basis. The difference between these two distributions is simply the addition of the
differential capital cost to the "bottom -line" net benefits.
Figures 3.10 and 3.11 show the distribution of net benefits for the contractor and force account
construction costs, respectively.
j Figure 3.10 - Probability Distribution of Net Benefits: Contractor Cost.
0.35
0.3
0.25
0.2
0 0.15
a
0.1
0.05
0
Probability Distribution of Net Benefits: Old Harbor
-------------------------------------
------------ El
O7 CD V: N O N fD a0 O
Q O b O O O O O O r
Net Benefits (million 1997$)
Figure 3.11 - Probability Distribution of Net Benefits: Force Account Cost.
0.35
0.3
0.25
0.2
:a
0 0.15
0
a
0.1
0.05
0
Probability Distribution of Net Benefits: Old Harbor
cat QD CR O N CD o0
O O O O r r r r r ('%i
Net Benefits (million 1997$)
LOCHER INTERESTS, LTD. PAGE 3.25 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
3.5.10.4 Financial and Utility Rate Impact Analysis
Under mid -range assumptions and contractor costs, AVEC system revenue requirements would increase
by about $385,000 during the first years of hydropower operation. This represents a 1.7% increase, or
about 0.8 cents per kWh. Revenue requirements with hydropower would not be lower than without until
the year 2021. About half of the increase in revenue requirements is due to increased margins; the cost of
service, which excludes margins, would only increase by about 1 %, or about 0.4 cents per kWh in 2002.
Table 3.13 below shows these results for other sets of assumptions.
Table 3.13 - Old Harbor financial results summary.
Old Harbor Financial ResultsSummary:
Increase ecrease in Average Revenue Requirement due to Hydro
(includes margins
Load
ue
Current Dollars
% Change from Diesel-onl
rowt
row#
2002
1 2005
2010
1 2020 2030
2002, 2005 12010
2020
2030
Contractor cost
mid
low
,3
360,1'76,
a
o7 1.3%
D
0.0%
- , d
mid
o ._7TGf
. o
0.0%
--UTTo
h l 9 h
. o . 3 o
n-
o-,
o
Force account cost
mid
low
,
I
o, o
o
- , o
- . o
mid
241,602
2 15,6:)
o, 0. o
o
-V207o
- . o
high
o . o
. a-
o
. o
Most Optimistic
(uses Force Acct Cost)
high high ,
,
a o
a-
o-U
7PTO
Most essimist_c uses ontrac or cost
low low
of 777o
- 1.0%1
0.1%,_-V6V.1
3.5.10.5 Break-even Analysis and Discussion of Economic/Financial Viability
Breakeven Analysis. In this analysis the major uncertainties are load growth and real fuel price growth.
Figure 3.12 shows the combinations of these two variables that lead to net benefits of zero, under both the
high and low construction cost assumptions. To fix the interpretation of this figure, consider the lower line,
which shows breakeven combinations for the low (force account) construction cost. This line crosses the
horizontal axis where load growth equals about 1.0%. This means that the combination of 1.0% load
growth and flat (real) fuel prices is sufficient to produce zero net benefits with hydropower. All
combinations above each line yield positive net benefits; all combinations below each line yield negative
net benefits.
LOCHER INTERESTS, LTD. PAGE 3.26 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Figure 3.12 - Combinations of load growth and fuel price growth for Old Harbor,
Breakeven Combinations of Load Growth
and Real Fuel Price Growth
4 0% Construction Cost 3.7 million
3.0% -------------------- Construction Cost 2.6 m5lion
2.0%----------- ` ---------------
'' 1.4%
o.a°io
.---- ------------------ ----------------
LL-2.0%------------------------------------
-3.4%
0.0% 1.0% 2.0% 3.0%
Load Growth
Discussion. Under the assumption of a low construction cost, the project is economic under a wide range
of load growth and fuel price growth rates. If contractor labor is used and the construction cost is
consequently high, there are not very many plausible combinations yielding positive net benefits.
However, since the project has substantial excess energy production at zero marginal cost, any
immediate and substantial increase in loads, such as off-peak heating or fish processing, would
dramatically improve the economics.
t
3.5.11 Regulatory and Permitting Issues
l Most of the Old Harbor project land would fall within KNWR boundaries, on lands owned in fee by the
United States (Table 3.14 below). This includes land that was patented to the Old Harbor Native
= Corporation (OHNC) and then later purchased in fee from OHNC. This land is subject to certain restrictive
covenants contained in the Warranty Deed from OHNC and the United States, as well as in the
Conservation Easement from OHNC and the State of Alaska.
Specifically, activities such as the construction of buildings or fences and the manipulation or alteration of
natural water courses are prohibited. The United States Department of the Interior, Office of the Solicitor,
has indicated that the three parties (OHNC, United States, and State of Alaska) should have the discretion
to act jointly to modify these restrictive covenants for a particular project, in as much as it is compatible
with the restoration and conservation purposes of the deed and easement.
Unofficial discussions with representatives of the USFWS and ADF&G have not revealed any opposition
towards such a resolution, at least on the part of the resource specialists who are evaluating the project.
Thus, assuming no policy or other reason exists for one of the three entities to oppose a joint modification
to the Warranty Deed and Conservation Easement, it would appear that the project should be a viable
development. Resource specialists have some concerns which will need to be addressed as a part of the
Applicant Prepared EA and FERC licensing process, and at present, AVEC is continuing to develop and
implement the required study programs. Based on the information available to date, and given the nature
and size of the proposed development, it appears reasonable to assume that the land issue, although
potentially serious, can be resolved.
LOCHER INTERESTS, LTD. PAGE 3.27 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE it
3.5.11.1 Land
Table 3.14 below lists the land selected under the interim withdrawal for this project (U.S. Department of
the Interior, Bureau of Land Management, Case Number AKA 077922). As discussed above, most of the
land (400 acres of the current 555 acre withdrawal) on which the project will be located is owned by the
United States. The remainder of lands on which project facilities may be located are OHNC lands (120
acres) or lands of the City of Old Harbor (35 acres). It is assumed that these latter lands pose no problem
in terms of project development as both the City and OHNC support the project.
Actual land area occupied by project features will depend upon final penstock and transmission line
routing as well as the amount and type of new access road required, but (assuming 60 ft rights -of -way)
should be well under 20 acres. Much of this area would be only temporarily disturbed.
Table 3.14 - Lands withdrawn under Preliminary Permit Number 11561-000 for Old Harbor.
+34 S
25 W 118
E1/2 SE 80 1 OHNC
34 S
25 W
18
NW NW
40 KNWR
134 S
25 W
18
NW SE
40 I KNWR
j 34 S
25 W
18
S1/2 NW
80 KNWR
34 S
25 W
18
SW NE
40 KNWR
34 S
25 W
19
NE NE
40 ! OHNC
34 S
25 W
20
W1/2 NW
35 I COW
34 S
26 W
12
E1/2 SE
80 KNWR
' 34 S
26 W
12
S1/2 NE
80 I KNWR
34 S
26 W
13
NE NE
40 !KNWR
Total 555 acres
'Old Harbor Native Corporation,
Kodiak National Wildlife Refuge,
3City of Old Harbor.
3.5.12 Environmental Conditions
Lands surrounding the community of Old Harbor, including almost all the land on which the proposed
project is to be located lie within the boundaries of the KNWR (see subsection 3.5.11.1) and are
essentially undeveloped. Aside from an existing off road vehicle trail originating near the pumphouse and
extending to the north along Lagoon Creek and beyond, there is little evidence of human use or
occupation in the area. Much of the project area vegetation is sub -alpine tundra, interspersed with dense
stands of willows, alders, birch, and occasional large, solitary cottonwoods in and along the creek
channels.
3.5.12.1 Terrestrial Flora/Fauna
No extensive surveys of the fauna of the project area have been completed at this time. The USFWS has
indicated in their comments on the preliminary permit application (USFWS, 1995) that the area can be
assumed to provide habitat for brown bear, Sitka black -tailed deer, beaver, and mountain goat. Nesting
bird species may include bald and golden eagles, marbled and Kittitz's murrelet, harlequin duck, and
surfbird. The two murrelets and harlequin duck are considered to be "species of concern" by USFWS
(species which appear to be declining, but for which information sufficient to justify proposal as threatened
or endangered is lacking).
LOCHER INTERESTS, LTD. PAGE 3.28 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE If
Additional information on wildlife use of area habitat and potential sensitivity to project development was
provided in a recent AVEC preliminary permit progress report (AVEC, 1997b) and is summarized below.
Mammals: No surveys have been completed of the terrestrial mammals in the project area. However,
Kodiak brown bear, Sitka black -tailed deer, mountain goat, red fox, land otter, beaver, weasel, snowshoe
hare, tundra vole, and little brown bat are assumed to be present.
Aerial surveys of brown bears in an adjoining area found a relatively high density of 270 bears11,000 kM2
(Barnes and Smith, 1997). Bear dens are present at elevations of around 1,000 ft and Barling Creek, Big
Creek, and Lagoon Creek all provide salmon feeding habitat for bears. Bears are reported to regularly
frequent the landfill. to the east of the pumphouse, as well as the lower stretches of Lagoon Creek (R.
Berns, personal communication).
The midslope habitat along the proposed penstock route reportedly is used as summer habitat for female
deer and their fawns, by rutting males in the fall, and provides winter habitat for both sexes.
Land ofter are present in both Barling and Lagoon creeks, and beaver are common in Barling Creek.
Red fox, mountain goat, weasel, snowshoe hare, tundra vole, and little brown bat all almost certainly are
found within the general project area.
Project impacts to the above species would likely include limited, short-term disturbance during
construction and possible periodic minor disturbance over the life of the project associated with occasional
maintenance activities. Impacts of significance only would occur if post -operational stream flows in
Barling or Lagoon creeks were adversely affected and resultant fisheries habitat impacts reduced
salmonid use of these streams, thus affecting bear feeding opportunities. As discussed below (subsection
3.5.12.2), the potential for significant fisheries habitat effects in these streams does not appear to be
great.
Birds: As indicated above, the USFWS has indicated that the harlequin duck and the Kittitz's and
marbled murrelets are species of potential concern and would require special measures to protect them
should they occur in the project area. AVEC (1997a) provided a report of a bird survey completed in
August, 1996. Total number of birds observed, by species, were recorded for the following five zones in
the project area:
I. Alpine ridge above diversion site,
IL Shrub thicket near diversion site,
III. Slope below diversion site to valley floor,
IV. Valley floor along creek bed below powerhouse, and,
V. Lagoon between pumphouse and Old Harbor boat harbor.
Table 3.15 below summarizes the results of the August survey. As shown, the most frequently recorded
species (gulls, ducks, yellowlegs, and sandpipers) are those associated with the biologically productive
coastal/aquatic system (Zone V). In general, the higher in elevation and further from the coast, the fewer
the number of species and individuals seen. This is in keeping with a common pattern in Alaska where
marine and coastal zone habitats (including anadromous fish streams) often are biologically more
productive and support more diverse populations than do many inland, high elevation habitats.
LOCHER INTERESTS, LTD. PAGE 3.29 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Table 3.15 - Birds observed in the Old Harbor proposed project area on 819l96 (AVEC, 1997).
j Glaucous winged gull j
111
1
110
Fox sparrow
i 42
2
19 21
I Mallard
40
40
Western sandpiper
30
I
j
30
Wandering tattler
1 29
I
29
Mew gull
I 20
1
20
i Wilson's warbler
I 14
1 !
2 [ 11
{ Savannah sparrow
11
1
1
4 I 1
4
f Least sandpiper
11
Green winged teal
10
j I
10
Hermit thrush
10
1 I 9
Common redpoll
8
6 2
Winter wren
7
I Semiplamated plover
6
I
6
Greater yellowlegs
i
1 6
I
6
I Black -capped chickadee
6
i i 6
Lesser yellowlegs
I 5
5
Golden -crowned sparrow
5
2 1
2
Arctic tern
4
4
Pine grosbeak
I 3
j 3
Bald eagle
3
3
Orange crowned warbler
2
I 2
Common raven
2
1
1
Black -billed magpie
2
2
Yellow warbler
2
2
Brown creeper
1
I 1
Rosey finch
1
1
Merlin
1
1
j
Totals
392
3
5
42 63
279
Project impacts to the bird fauna of the area likely will be minimal. Little land will be physically impacted by
project construction (see 3.5.11.1 above) and much of the area that will be disturbed is in the less
productive zones 1-111. No eagle or other raptor nests have been identified in areas that might be affected
by the project. Assuming little or no fishery impact, effects on local avifauna should be limited to minor
short term disturbances associated with project construction and infrequent disturbance related to
maintenance activities over the life of the project.
None of the three USFWS species of concern were reported from the August survey. Additional and more
detailed studies will be necessary to completely address USFWS concerns for these species, however.
3.5.12.2 Fisheries
ADF&G records indicate that coho, chum, and pink salmon, as well as dolly varden, spawn in the lower
reaches of Barling Creek and in the lower and middle reaches of Lagoon Creek (Exhibit A5).
AVEC (1997a) reported on the results of 1996 fish surveys, conducted in these two drainages. In August
1996, field sampling was conducted at six sites in Barling Creek and one site in Lagoon Creek, using a
LOCHER INTERESTS, LTD. PAGE 3.30 JANUARY 09, 1998
1
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
backpack electroshocker and minnow traps (Exhibit A5). At the time of this survey, the lower 0.75 mi of
Barling Creek and the lower 1 mile of Lagoon Creek were dry at the surface. Results of this sampling are
summarized in Table 3.16 below.
Table 3.16 - Results of August 9, 1996 fish sampling in Barling and Lagoon Creeks.
Barling Creek 1
0
0
Barling Creek 2
0
Not Sampled
Barling Creek 3
0
0 I
Barling Creek 4
0
Not Sampled
Barling Creek 5
0
Not Sampled
Barling Creek 6
0
dv = 1; co = 8
Lagoon Creek 7
0
dv = 26; co = 9; ss = 2
dolly varden,
2Coho salmon,
3slimy sculpin.
No fish were taken by electroshocking at any of the sampling sites on either creek. On Barling Creek, two
species were reportedly observed at site 6, the most downstream station: 8 coho, and 1 juvenile dolly
= varden were sampled by minnow trap. On Lagoon Creek, 26 dolly varden, 9 coho salmon, and two slimy
sculpin were taken by minnow trap at site 7, located upstream of the proposed location for the
powerhouse.
Adult salmon surveys of the Barling and Lagoon creek drainages were conducted once in August
(helicopter) and twice in September (on foot) during 1996. Results were characterized as inconclusive
due to low water conditions in portions of both stream systems.
No fish were reported in the upper section of Barling Creek. Ten thousand pink salmon were reported in
the lower section of Barling Creek during August, with 1,000 sighted in early September and 200 in late
September. Eighty (80) coho salmon were also reported for the late September survey.
The August survey reported 80 chum salmon for Lagoon Creek. September foot surveys recorded 30
chum salmon early and 18 chum and 2 pink salmon during the later survey.
J Estimates of the potential spawning habitat in these two streams, including both the wet and dry sections
as reported by AVEC (1997a) are 119,000 sq ft in the East Fork of Barling Creek (equivalent to suitable
habitat for the equivalent of 11,120 females or 22,240 pairs) and 92,000 sq ft in Lagoon Creek (8,750
females; 17,500 pairs).
At present, it appears that the intake site is well upstream from any spawning habitat and the section of
East Fork Barling Creek above the diversion is of limited or no value for fish. There will be no blockage of
fish movements in Lagoon Creek.
As a transbasin diversion project, the Old Harbor project will have the effect of reducing the total annual
discharge in Barling Creek and will increase annual discharge in Lagoon Creek. Reduction of discharge in
Barling Creek could have some impact on the spawning habitat in the lower watershed. However, this
effect will likely be ameliorated to some degree due to the significant amount of intervening drainage in the
Barling Creek Basin between the proposed diversion and the upper limits of the spawning areas. Water
will be diverted out of the basin from only about 1.7 sq mi of the upper basin (22% of the total basin). The
remaining 6 sq mi (78%) of the drainage will be unaffected. Factoring the effect of elevation on
LOCHER INTERESTS, LTD. PAGE 3.31 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
precipitation (approximately 0.003 cubic feet per square meter per foot of elevation gain), the area above
the diversion site probably produces about 26% of the total discharge for the entire basin. However, the
Old Harbor Project has no storage component, and at discharges above the hydraulic capacity of the
turbine, excess water from the diversion area will flow to lower Barling Creek.
High flow events in Barling Creek will be largely unaffected by the project, as all flows above the hydraulic
capacity of the turbine will continue to flow through the Barling Creek system. Low flow periods will be
more likely to be affected, but again, about 74% of the total system discharge will remain in Barling Creek
and be available in the lower sections of the stream which support salmon spawning.
Spawning habitat in Lagoon Creek should be improved due to the higher flows available below the
powerhouse. Particularly, if project operation stabilizes winter flows in lower Lagoon Creek, the project
could benefit the saimonids rearing in this drainage. Experience at both the Terror Lake and the Bradley
Lake hydroelectric projects indicates that elimination of extreme low flow events in winter is beneficial to
salmonid survival (Blackett of al., 1992; Northern Ecological Services, 1996).
Additional fisheries studies, currently being developed by the applicant in coordination with the resource
agencies, will be necessary to more precisely define the degree of impact that the project might have on
Barling and Lagoon creek fisheries. However, at this time it would appear that fisheries impacts will be
within acceptable limits and should not preclude project licensing. Because of the substantial intervening
flows available below the diversion site on Barling Creek, no minimum flow releases from the project have
been assumed. However, given that the project, as planned, will be capable of producing substantially
more energy than the existing system can absorb, it is considered highly likely that a minimum flow
requirement would have little or no effect on the economic viability of the project, at least in it's initial
years.
3.5.12.3 Cultural Resources
AVEC (1997b) has provided results of a cultural resources evaluation for the project area. A cultural
resource team performed a field evaluation of the site in 1996, including visual inspection of the
transmission line corridor, powerhouse site, and penstock alignment. This visual examination was
supplemented by examination of subsurface sediments for cultural materials using a 1.5 in soil probe, wlth
occasional shovel tests where soil probes were unable to penetrate frozen sails. Along the transmission
line alignment, paired soil probe samples, spaced approximately 30 meters apart, were taken at 25 meter
intervals, with spacing and intervals modified as necessary to accommodate specific ground conditions.
Along the proposed Polarconsult penstock alignment, subsurface samples were taken only in areas
considered probable locations for archaeological deposits (level, well drained areas on ridgetops, knobs,
or terraces).
No prehistoric cultural deposits were located during this survey, nor were recent cultural sites of scientific
significance reported. Further, it is considered unlikely that any prehistoric or historic remains exist in the
project area as surveyed.
J One significant site is known to exist in the general area (ca 200 m south-southeast of the water treatment
facility) and project planning must take the location of this site into account so as to avoid any direct or
indirect impacts thereto. It does not appear that this will pose any problem for the development of the
proposed project.
LOCHER INTERESTS, LTD. PAGE 3.32 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
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4. UNALASKA
4.1 LOCATION
The Pyramid Creek watershed, location of the potential hydroelectric projects discussed herein, is located
to the southwest of the most developed portion of the City of Unalaska, on Unalaska Island, in the Aleutian
Archipelago near 53050' North latitude, 166°30' West longitude. As analyzed herein, the development of
the hydroelectric potential of the Pyramid Creek basin would involve tapping the existing water supply
pipeline near the chlorination building and running a penstock to a powerhouse at tidewater near
elevation 20. Exhibits B1 and B2 provide details on the watershed features and stream locations. Exhibit
B3 shows the location of the potential hydroelectric sites within the Pyramid Creek basin evaluated for
development, including the selected development.
4.2 GENERAL DESCRIPTION OF THE AREA
Bound by the Pacific Ocean to the south and the Bering Sea to the north, the Aleutian Archipelago is
comprised of a chain of over 200 named islands, stretching along an 1,100 mile arc from Attu Island in the
east to Unimak Island in the west. The Aleutians are generally topographically rugged, treeless islands
dominated by a maritime climate, with mean annual temperatures on the order of 40OF and annual
precipitation in excess of 50 in. Unalaska and Amaknak Islands are part of the Fox island group, located
in the central portion of the Aleutian chain.
4.2.1 Unalaska and Amaknak Islands
A part of the geologically young, tectonically active Aleutian Archipelago, Unalaska Island and its smaller
neighbor, Amaknak Island, are characterized by mountainous terrain, with peaks in the immediate vicinity
of the City rising abruptly from sea level to elevations in excess of 2,000 ft. The Makushin Volcano
(reaching to elevation 6,680 ft) is one of several active volcanoes in the Aleutians, and is located on
Unalaska Island 14 mi northwest of the City of Unalaska. Mt. Makushin has been investigated repeatedly
as a potential source for geothermal power development.
Area topography on Unalaska Island is a product of the interaction of past glaciation and past and ongoing
tectonic and alluvial action, and as a result, area streams tend to be relatively short and steep with rapids
and waterfalls commonly isolating the upper drainages from tidewater areas.
As is the case for most of the Aleutian Islands, Unalaska and Amaknak islands are virtually treeless.
Vegetative communities in the project area are mainly upland tundra, dominated by crowberry, willow,
lichens, mosses, and sedges. The climate is dominated by maritime influences with January
temperatures ranging from 25 to 35 °F and summer temperatures from 43 to 53 OF. Average annual
precipitation is 50 in with snow persisting at higher elevations over most of the winter but with repeated
thaws at or near sea level.
4.2.2 Unalaska/Dutch Harbor
The City of Unalaska is located on Unalaska and Amaknak Islands, in the eastern Aleutian Islands,
approximately 800 air miles southwest of Anchorage. Overlooking lliuliuk Bay and Dutch Harbor, the City
is connected by a bridge constructed across the Bay in 1980, unifying the Unalaska and Amaknak island
populations into a single community. That portion of the City located on Amaknak Island is often referred
to as Dutch Harbor.
LOCHER INTERESTS, LTD, PAGE 4.1 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
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As discussed below, Unalaska is dependent upon fishing, seafood processing, and fleet services for its
economic base. During peak periods of the pollock fishery, there is an influx of up to 3,000 temporary
workers, of various backgrounds and nationalities, filling various positions with the land based seafood
processing or fleet support services.
At the time of the 1990 census, the unemployment rate was only 1 %, median income was $56,215 and
approximately 15% of the population was living below the poverty line. There are two schools (K-12),
attended by 415 students, and a local health clinic. A full complement of City services including water,
power, sewage treatment, and refuse collection and disposal are provided by the municipality.
4.2.2.1 Population
In the mid-1700s, when Russia first established a trading port for the fur seal industry, there were an
estimated 1,000 Aleuts, living in about 24 settlements on Unalaska and Amaknak islands. By the early
1800s, only about 200-300 Aleuts remained, and during World War 11, almost all the Aleuts were interned
to Southeast Alaska. Today, only 8.5% of the population is Native.
The current resident population of Unalaska is approximately 4,100. As shown in Table 4.1 below, this
population has increased steadily over the past seven years, although the rate of increase has slowed
somewhat, possibly partially due to shifts in the fishing industry towards increased offshore processing.
This is in contrast to the period from 1980 to 1990 when population growth in Unalaska averaged 9%, as
compared to 3% for the rest of the State (HDR, 1995).
Table 4.1 - Alaska Department of Labor population data for Unalaska.
Population 1 3089 3370 3656 3780 3916 396 1 4087
Percent Change I n/a +9.1 +8.5 +3.4 +3.6 +1.3 1 +3.0
4.2.2.2 Economic Base
Seafood dominates Unalaska's economy. Commercial fishing, fish processing, and fleet support services
provide the majority of the employment opportunities in the area. There are six major, and several
smaller, seafood processors and over 250 marine support businesses in Unalaska, employing more than
3,000 people and accounting for 90% of the economic activity. Over 90 residents hold commercial fishing
permits. The harbor accounts for over 50% of Alaska's commercial fisheries value and regularly ranks as
the number one port in the Nation for seafood production, both in terms of total volume and value.
Beginning in the early 1980s (with the growth of a crab fishery) and again in the late- 1980s/early-1990s
(as the groundfish industry grew), Unalaska underwent rapid growth. More recently, growth has slowed
as the work force has been reduced in response to reduction in pollock harvests as well as a trend
towards offshore processing of the catch by factory trawlers. Concurrently, tourism has begun to develop
as a more significant economic activity, with over 6,000 cruise ship visitors during 1996. However, this
increased tourism industry has not reached a stage where it rivals the importance of fisheries related
economic activity.
4.3 EXISTING POWER SYSTEM
The City of Unalaska Electric Utility is the only supplier of public power in Unalaska. The system consists
of nine diesel generators, eight of which are located at the City owned power plant on Amaknak Island,
with one generator located south of the City center on Unalaska Island to provide secure power in the
case of a disruption between the Islands. In addition, seven private companies (e.g. seafood processors)
LOCHER INTERESTS, LTD. PAGE 4.2 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
have their own diesel generators with a capacity of one megawatt (MW) or more. Currently, all diesel
generators, including the City's, face potential problems related to allowable emissions limits.
4.3.1 Installed Capacity
The City Utility currently has a total installed capacity of about 7.5 MW, as shown below in Table 4.2.
Table 4.2 - Capacity of existing City Utility diesel units.
11
11
.Ii
1
. 1
•
� 1
111
1
I�
•
11
'Located at City Power Plant on Arnaknak Island,
2 Located on Unalaska Island.
In addition, there is 36.3 MW of additional installed capacity available in Unalaska at seafood processors
and associated industries, as follows:
Table 4.3 - Additional installed capacity available from independent providers.
M AMMMIM
Unisea 16.5 MW
Westward Seafoods
6.9 MW
Alyeska Seafoods
6.4 MW
Icicle Seafoods
2.1 MW
American Presidents Line
1.7 MW
Sealand
1.4 MW
Offshore Systems, Inc.
1.3 MW
4.3.2 System Loads
Commercial users (i.e. fish processors and support industries) consume the bulk of the power produced
by the City. In fiscal year 1997, Unalaska Utilities power sales were 76% commercial, 16% residential, 7%
community facilities, and 2% State and Federal facilities.
4.3.2.1. Annual
As shown below (Table 4.4), total annual generation has risen consistently over the past five years, while
energy sales, which rose sharply in the early 1990s, have declined over the past two years, probably in
response to a downturn in the seafood processing industry. The City regularly purchases additional power
from one of the seafood processors listed in Table 4.3 above in order to meet peak loads.
LOCHER INTERESTS, LTD. PAGE 4.3 JANUARY 09, 1998
1
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
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Table 4.4 - Unalaska annual generation, purchases, and sales (kWh) for Fiscal Years 1992 -1997.
kWh Generated
20,771,000 21,910,000 25,183,000 26,566,000
27,185,000
29,926,000
Percent Change
Generation
n1a
+ 5.5
+ 15
+ 5.5
+ 2.3
+ 11.0
kWh Sold
18,348,000
j 20,868,000
24,354,000
28,580,000
27,280,00D
26,760,000
Percent Change
Sales
nla
I + 13.7
I
+ 16.7
+ 17.4
- 4.5
-2.0
kWh purchased
0
I 546,000
998,280
4,477,200
1 2,426,000
369,000
Unalaska power purchases, by month, for the period from July 1992 through September 1997 are shown
in Figure 4.1 below.
Figure 4.1 - Power purchased by the City of Unalaska.
Unalaska : Purchase of Power from Others : 711191-9130/97.
900000 -
i
600000
700000
600000
m
II
500000 i
r
IL
I
400000
x jI
300000 I
200000
k
I
100000
m N m n 0 m m m m m o�i ou'i 0 m m W rn m in m rn
O 4 O W Q O Q O ¢ O 6 '-'
Month
According to PCE filings for fiscal year 1996, station service was about 3.7% of the total power generated
while line losses equaled 8.0%.
4.3.2.2 Average Monthly Power Sales
Monthly energy sales by Unalaska Electric Utility, averaged for the past six fiscal years are shown in
Figure 4.2 below, The pattern shown reflects the effects of the early (January through March) and fall
(October and November) pollock seasons, as well as an increased winter residential demand.
LOCHER INTER
ESTS, LTD. PAGE 4.4 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE 11
Figure 4.2 - Monthly energy sold by the City of Unalaska.
Unalaska: Average Monthly kWh Sold for Fiscal Years 1992 -1997
3000000
2500000
k
2000000
1500000 j
Y
I
I
1000000
i
500000
0
jan fob mar apr may jun jui pug Sep Oct nov dec�
Month
4.3.2.3 Peak Load
Peak generation by month, based on the last six years of PCE program filings with the DOE, is
summarized below. A February 1995 peak of 5,730 kW (5.7 MW) is the highest value reported, and
February and March appear to be the peak demand months over most of this time.
Actual system peak demand is substantially higher than the values shown in Table 4.5, as these data are
for power generated by the utility only and do not reflect additional power purchased from the seafood
processing industry which supplements City generation_ The City reports a total peak demand of about
6.5 MW in 1994, significantly higher than the 5,125 kW peak recorded below for February of that year
(HDR, 1995). Peak demands coincide with the pollock seasons early in the year and in the fall_
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ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
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Table 4.5 - Unalaska system peak demand (kW) by month for 1992 through 1997.
'January
i February
March
n/a
n/a
n/a
4160
4435
4170
3845
4850
5125
5430
5730
; 5195
4160 4120
5510 5505
5295 5265
April
n/2
3705
3960
52 00
4545
4500
May
nla
3280
3830
4010
4740
3950
;June
n/a
3155
4130
3690
3915
3400
July
2565
3600
4260
1 4230
4090
3500
j August
2530
3260
453p
4575
4460
3615
! September
2900
3760
4920
4930
4690
n/2
October
3270
3705
4560
4045
4750
n/a
November
3475
3840
4865
4230
4535 1
n/a
December
3855
448fl
4760
4200
4240
n/a
4.4 HYDROELECTRIC DEVELOPMENT ALTERNATIVES
Several investigations of hydroelectric power developments for Unalaska have been completed in the
past. These include a feasibility report prepared by the U. S. Army Corps of Engineers (USACOE, 1984)
which looked at potential developments in the Pyramid Creek Basin as well as a larger development on
the Shaishnikof River, and preliminary evaluations of several development schemes in Pyramid Creek by
consultants and developers (Energy Stream, Inc., 1985; Polarconsult, 1993 and 1994).
As detailed below, these evaluations covered four basic development options for the Pyramid Creek
Basin. These are:
• Addition of a small (ca 100 kW) turbine/generator to the existing water supply system, to replace the
pressure reduction valve, and capture the energy available from the City water supply.
• Diversion of additional water into Icy Reservoir and addition of a turbine and generator at the low point
of the existing water supply pipeline to generate additional power (ca 350 kW).
• Creation of an additional diversion structure in the basin to supply water to a small turbine/generator,
but returning the water directly to the stream (ca 350 kW).
• Creation of an additional diversion and installation of additional pipeline to supply water to a
powerhouse located near tidewater (ca 1,350 kW).
Virtually all the earlier investigations included utilization, to some extent, of the City of Unalaska's existing
water supply system to supply some or all of the flows. In most cases, use of the existing water supply
pipeline was also a part of the proposed development scheme.
Since the completion of the above cited investigations, the City has undertaken a substantial
modernization of their water supply system. This includes a 1994 replacement of the original Icy Creek
Reservoir diversion structure and its 16-in diameter woodstave pipeline, referred to in previous reports,
with a newly constructed diversion at the same site and a newly placed 24-in diameter cast-iron conduit to
pipe water from behind the diversion to the water quality treatment plant. Also, a second diversion
structure was constructed at the outlet of Icy Lake, near the top of the Pyramid Creek drainage. This new
diversion, located on an existing lake, was completed in 1996 and provides the City with a backup water
supply. Icy Lake provides a storage capacity of 60 million gallons (mg). A siphon outlet, controlled by a
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manually operated outlet valve, returns regulated water to the creek approximately 1/4 mi below the
diversion. Exhibit B2 provides the location of these upgraded facilities in the basin.
Because the system as it exists today is considerably different than that which existed when previous
investigators completed their work, we have re-evaluated the hydroelectric power potential of the basin
taking existing conditions into account. As detailed below, the same basic options evaluated by the
previous investigators still apply, although the specific developments differ in certain aspects.
Alternative hydroelectric developments proposed within the Pyramid Creek watershed are shown in
Exhibit B3.
4.4.1 Energy Recovery from Existing Water Supply Pipeline (Alternative 1)
The Energy Stream Inc. (ESI), Polarconsult, and U.S. Army Corps of Engineers (COE) reports all
considered an alternative where energy was recovered from flowing water in the City's existing potable
water main. ES1 and Polarconsult sized the unit at 90 and 100 kW, respectively. The COE sized the unit
at 260 kW, but used water demand plus surplus water to run the turbine.
Currently, at or near the existing chlorination building, the water pressure is reduced with a pressure
reducing valve (PRV). Drinking water supply is then chlorinated and stored in a 2.6 mg water tank. At the
PRV, or immediately upstream of the PRV, a pipe loop would be installed around the PRV, and a 50 kW
turbine installed in the line utilizing the City's water demand flow. The head on the plant consists of the Icy
Creek reservoir level less the level of the water in the storage tank (188 ft assumed). Extending the
existing chlorination building, or a separate small pre -fabricated metal building would serve as the
powerhouse. A transmission line would be installed in the existing buried PVC conduit to Captains Bay
Road or tied into the existing 15 kV single-phase power supply line to the chlorination building.
This alternative can be constructed in conjunction with each of the following alternatives indicated in
paragraphs 4.4.2 through 4.4.5 below.
4.4.2 Blow -off Location on Existing Water Supply Pipeline (Alternative 2)
As the existing water supply pipeline traverses from Icy Creek Dam to the chlorination building, there is a
low point at approximately elevation 262 where a blow -off (drain) valve is located_ At the blow -off valve,
the pipeline would be tapped to intercept water with an additional pipe provided to direct water to a turbine.
A similar alternative to this was considered by Polarconsult, although they wanted to locate the
powerhouse in the Pyramid Creek gorge, which would make construction and maintenance access difficult
and costly. The alternative of this report is essentially a combination of Polarconsult Options 1 and 2 (the
water pipeline has been replaced since their study and, therefore, the distances and locations do not
match). Alternative 2 herein would consist of replacing the blow -off valve with a bifurcation (wye) and
short pipeline (< 50 ft) to a pre -fabricated metal building powerhouse founded on bedrock at about
elevation 255. A 300 kW turbine would use water surplus to the water supply system at a gross head of
` about 263 ft. Water exiting the turbine would be conveyed in a pipe or open channel and run over the rock
gorge wall, dropping about 30 ft into Pyramid Creek. A buried transmission line would be installed in a
new PVC conduit to the chlorination building and in the existing spare PVC conduit to Captains Bay Road.
4.4.3 New Diversion Below Confluence with a Powerhouse at Tidewater (Alternative 3)
Alternative 3 is mentioned in ESI's report and involves constructing a diversion below the confluence of
the East Fork of Pyramid Creek and Icy Creek. Water unused by the water supply system, spilling over
Icy Creek Dam, and the flow from the East Fork would be impounded by a low height dam and conveyed
in a penstock to a powerhouse near tidewater at about elevation 20. The gross head on the plant would
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be 295 ft, enabling a 600 kW turbine to be installed as compared to 350 kW estimated by ESI. The
powerhouse would be a pre -fabricated metal building. Water exiting the turbine would be conveyed in a
pipe or open channel to Pyramid Creek. A buried transmission line would be installed in a new PVC
conduit to the existing 15 kV 3-phase line paralleling Captains Bay Road.
4.4.4 Tap Existing Water Supply Pipeline with a Powerhouse at Tidewater (Alternative 4)
This scenario involves tapping the existing water supply pipeline near the chlorination building and running
a penstock to a powerhouse at tidewater near elevation 20. ESI estimated that a 1,000 kW plant could be
installed using surplus water from Icy Creek Dam. At a gross head of 498 ft, we estimate that a 600 kW
unit can be installed. The powerhouse would be a pre -fabricated metal building. Water exiting the turbine
would be conveyed in a pipe or open channel to Pyramid Creek. A buried transmission line would be
installed in a new PVC conduit to the existing 15 kV 3-phase line paralleling Captains Bay Road,
4.4.5 Diversion of East Fork Pyramid Creek Flows to Icy Creek Reservoir (Alternative 5)
This scenario involves constructing a small diversion dam about 2,5D0 ft up the East Fork Pyramid creek
from its confluence with Icy Creek_ Water would be diverted from the East Fork through a pipeline to Icy
Creek Reservoir. A new penstock would run from Icy Creek Dam, paralleling the waterline to the
chlorination building, to a powerhouse at tidewater. At a gross head of 498 ft, we estimate that a 1,000
kW unit can be installed. The powerhouse would be a pre -fabricated metal building. Water exiting the
turbine would be conveyed in a pipe or open channel to Pyramid Creek. A buried transmission line would
be installed in a new PVC conduit to the existing 15 kV 3-phase line paralleling Captains Bay Road.
By inspection, we have ruled out this alternative out -of -hand as being too costly for the hydroelectric
benefit received. However, this alternative would provide a side benefit, in that additional water would be
diverted to the City's water supply reservoir, therefore, enhancing reliability.
4.5 SELECTED ALTERNATIVE
Of the five alternatives subjected to preliminary evaluation, four were taken to the next level of study
(Alternatives 1 through 4). Feasibility level energy computations and cost analyses were performed for
each of these four. Table 4.6 below compares energy output with estimated project development costs.
Table 4.6 - Energy vs, cost comparison of Pyramid Creek hydroelectric project alternatives.
Based on the above analysis, Alternative 4 is the lowest cost per installed kW. Alternative 4 has twice the
energy output as Alternative 2 (with slightly lower dollars per kW costs) and has nearly the same output as
Alternative 3 (with about 35% less cost). Alternative 4 will be the basis of further analysis and the
preferred alternative selected for this report.
For each alternative, water is taken directly from the water supply system. As the demand for City water
is increased, only Alternative 1 will have increased energy output. The energy benefits of the other
alternatives would be eroded as the demand for water increases. However, Alternatives 3 and 5 may be
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less affected by future demand because part of the water used to generate electricity comes from East
Fork Pyramid Creek. For a more detailed explanation of the effect of water withdrawal for City supply on
Alternative 4, see subsection 4.6 below.
4.5.1 Project Location
The location of the selected alternative within the Pyramid Creek watershed and proposed locations of the
powerhouse, penstock, tailrace, access road and transmission line are shown in Exhibit B4. As shown,
the project utilizes the existing water supply pipeline near the chlorination tank and routes water through a
penstock to a powerhouse located at tidewater near elevation 20. Water exiting the turbine -would be
conveyed in a pipe or open channel and returned to Pyramid Creek.
4.5.2 Current Project Development Status
At present, there are no hydroelectric power feasibility studies or FERC permitting activities underway for
the Pyramid Creek Basin. The City of Unalaska recently issued a Plan for Improvements to their utilities
(HDR, 1995). This document addresses both the Makushin Geothermal Project, planned to make 12 MW
of power available to the City, as well as the development of the Pyramid Creek Basin hydroelectric power
potential, possibly providing an additional 1,500 kW of power. At the time of preparation of the Utilities'
improvements plan, emphasis was on the geothermal project, and hydroelectric power was given second
priority status.
Since the report was issued, support for development of the Makushin Project has faltered due to lack of
funding; consequently, interest in the hydroelectric power potential of the Pyramid Creek area has
increased. However, no active program is underway at this time. The City is highly interested in pursuing
a hydroelectric power development, particularly if a source of funding can be identified.
The City is currently seeking a consultant to assist them in completing a comprehensive power planning
program.
4.5.3 Topography/Drainage Basins
The mountains forming the Pyramid Creek drainage area rise abruptly from the sea to elevations of
around 2,500 ft. As typical of many streams in the mountainous Aleutian Islands, Pyramid Creek is a
relatively short, steep stream. With the tributary streams East Fork Pyramid Creek and Icy Creek
(Exhibits 61 and 132), the entire Pyramid Creek Basin covers an area of approximately 5.1 sq mi. From
Icy Lake Reservoir, at elevation 720 ft, the stream drops to sea level over a distance of approximately 3.75
mi, for an average slope of 192 ft/mi.
Icy Lake Reservoir, constructed in 1994, near the top of the watershed has a surface area of
approximately 18 acres with a maximum depth of 25 ft and storage capacity of 50 mg. Runoff from the
surrounding mountain peaks drains into Icy Lake, and accounts for only 0.2 sq mi or 4% of the total
drainage area. Correct nomenclature for the name of the stream draining the reservoir is Icy Creek.
A water supply reservoir is located approximately 1.5 miles downstream from Icy Lake outlet. This
diversion, reconstructed in 1994, allows water withdrawal for City treatment and supply. The contributing
drainage area to the diversion outfall is 2.7 sq mi, or 57.7% of the total drainage area. This reservoir, with
storage capacity of 9 mg, has a significant influence on the magnitude and timing of stream runoff.
In the lower portions of the stream, bedrock outcroppings have created two large falls, located
approximately 1,800 and 6,600 ft from the mouth and approximately 60 and 180 ft in height, respectively.
Additionally, smaller falls and rapids are present throughout the remainder of the drainage. Only at the
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RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE 11
mouth, just above tidewater, and in a short stretch of stream immediately upstream of the Icy Creek
Reservoir, does the drainage traverse any relatively flat areas.
The main stem has three tributaries. East Fork Pyramid Creek heads at elevation 1200 to the east of the
main channel and has a drainage area of 1.3 sq mi, or 28.2% of the total drainage as seen at tidewater.
The other two unnamed tributaries contribute flow between Icy Lake and the water supply reservoir. One
flows west to its confluence midway between the two reservoirs and drains an area of 0.5 sq mi. The
other heads in a glacial cirque, known locally as Snow Basin, and flows west to its confluence with icy
Creek approximately 500 ft below Icy Lake, draining an area of 0.6 sq mi.
As is true for almost all the Aleutian Islands, the basin is virtuaily treeless. It is well vegetated, however,
by the tundra communities typical of the Aleutians.
All of the drainage basin is readily accessible. The Locher design team was able to walk nearly the full
length of both the upper and lower watersheds, from the divide to tidewater.
4.5.4 Geology/Soils
The Aleutian Islands, geologically the youngest region in Alaska, are the crests of an arc of submarine
volcanos. The region is generally underlain by Cenozoic basalt and andesite lava flows. The cliffs along
the lower section of Pyramid Creek indicate that local bedrock consists principally of a calcareous mixed
fine- to medium -grained conglomerate (USACOE, 1984). Other rocks in the area include a siliceous,
cherty, fine-grained sandstone and cobbles of quarzitic graywacke. Soils are generally well drained
volcanic ash with a loamy texture. In many areas, the stratigraphy soil includes large quantities of peaty
materials produced by the extensive growth of sphagnum moss and associated tundra vegetation
common in the area.
As expected for a volcanically active area, potential mineral resources occur in the general project area.
An auriferous quartz vein is known on Pyramid Peak, although it is reported to be of insufficient grade or
quantity to be economic (USACOE, 1984).
The Icy Creek/Pyramid Creek basin is underlain with andesitic bedrock, probably with little or medium
depth cover (0 to 10 ft). Excavations and penstock trenching will probably encounter silty sand, gravel,
bedrock, and/or medium to large cobble. The creek bed is comprised of bedrock outcrops, gravel, and
small to medium sized stones. It is assumed that any diversion structures required would be founded on
competent bedrock with minimal excavations. The powerhouse would be founded on bedrock or native
granular material.
4.5.5 Hydrology
The Pyramid Creek basin (Exhibit B1) is located approximately 3 mi south of town, with a total drainage
area of 4.9 sq mi from the watershed divide to tidewater. The drainage basin is dissected by Icy Creek
from where it heads into Icy Lake near the divide, and flows north and northwest to its mouth at Captain's
Bay near Obemoi Point. The major contributing stream received by Icy Creek, East Fork of Pyramid
Creek, heads south of Pyramid Peak and flows west to its confluence. The City's water supply reservoir is
located just upstream from the confluence, along Icy Creek. Due to the proximity of Icy Creek to Pyramid
Peak, the nomenclature for the stream system changes to Pyramid Creek below the confluence.
The basin is free of glaciers, and has one natural lake and one reservoir. Icy Lake is located at the
headwaters of Icy Creek, at elevation 722 ft.
LOCHER INTERESTS, LTD. PAGE 4.10 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
The climate in Unalaska is influenced by marine conditions, including cool temperatures, cloud cover,
moderate rainfall, and nearly constant wind.
Summer temperatures range from 43-53°F; winter temperatures range from 25-35°F. Mean annual
precipitation is 50.1 in and includes water equivalency of 72 in of snow. Winds average 11 mph from the
southeast. Snow accumulates at higher elevations through winter along the mountain sides and in the
glacial cirque, though peaks are frequently blown free of snow cover.
4.5.5.1 Existing Data
From March of 1994 through the present, DNR has gaged 5 points within the watershed to characterize
basin streamflow, located as shown in Exhibit 131. At the lower three sites (one each directly upstream of
the confluence and one near tidewater), recorded stage height has been correlated with cross -sectional
area and point velocities to determine daily average discharge in cubic feet per second. At the upper-
most gaging sites, above icy Creek Reservoir, only stage has been recorded and has not been coupled
with velocity measurements to determine discharge. Thus, preliminary information released by DNR from
the lower three sites has been used to characterize Icy Creek and Pyramid Creek contributions. A final
stream gaging report authored by DNR hydrologists is expected to be available in 1998, Following a
spring flood event, the uppermost stream gage at Icy Lake outlet has been replaced by a precipitation
gage. That information will also be provided with the DNR final report upon completion of their gaging
contract.
Precipitation has been recorded at the Dutch Harbor airport from 1922-1954, and from 1982-present. A
hydrograph using monthly average precipitation for the 46 year period -of -record is shown in Figure 4.3.
Average precipitation by month is shown in Figure 4.4. The 46-year average annual precipitation
recorded at the gage site is 60.1 in; the average monthly precipitation recorded is 5.0 in.
Figure 4.3 - Long-term average precipitation.
I
20
18
a 16
;a 14
.2- 12
i 10
6
N 6
u
4
C 2_
0,
N
I N
G
Average Monthly Precipitation (in)
M L 0 +- n � r- M 0 N r u7 r
CV N N C�3 C7 C? C? C? '7 V
= c4 U ' C], tC6 U tl n
O Q -7 O Q O
Month
Q, r N N o f L n n O " "r "
9 4? Ca C9 w m M o3 M M
LOCHER INTERESTS, LTD. PAGE 4.11 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Figure 4.4 - Average precipitation by month.
8.00
7.00
6.00
5.00
L
O
4.00
.m 3.00
Q
2.00
1.00
0.00
Unalaska Averane Mnnthiv Prorinifnfinn 4019_D�---4.
January klarch Way July Septerrber November
Month
IFigure 4.5 - Yearly difference from average annual precipitation.
a
Unalaska
Yearly Difference from Average Annual Precipitation (50.1 in)
4n nn
Precipitation trends during the gaging period of record indicate that 146% higher than average
precipitation was received in 1994, 121% higher in 1995, and 115% higher in 1996. Correlation between
the overlapping periods of gaged precipitation and stream discharge allow an adjustment of measured
discharge to better predict expected long-term runoff. Deviation of precipitation from the long-term
average for each year of record with associated multipliers used to adjust the discharge data is shown in
Table 4.7 below. All multipliers used were less than 1, indicating that years 1994 through 1996 were
above normal years, and associated gaged data is adjusted downward to reflect expected runoff trends.
After adjusting water yields based upon long-term climate trends, the streamflow data collected at the
confluence gage were adjusted for the project area by both drainage size and elevation.
LOCHER INTERESTS, LTD. PAGE 4.12 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASEI1
Table 4.7 - Multipliers used to adjust gaged stream data for Pyramid Creek.
Average Annual Precipitation at
50.1
73,1
60.8
57.8
Unalaska (in)
Percent of 75-year mean
1.00
1.46
1.21
1.15
Factor used to adjust daily
1
0.68
0.83
0.87
stream discharge
Using the 4 years of adjusted gaged data, the daily means and standard deviations were calculated and
used to stochastically generate a 10-year simulated dataset of 365 synthetic daily averages at the project
site.
4.5.5.2 Assumptions
Runoff calculations account for basin size and elevation, but do not consider temporal or local effects of
exposure and location. Average daily streamflow also assumes runoff as a direct function of monthly
precipitation averages and their deviation from long-term means, and do not consider local or seasonal
effects (frozen soil, antecedent moisture, vegetative cover) that may alter water yield, magnitude, or timing
following a given precipitation event.
4.5.5.3 Predicted Runoff
Based upon DNR stream gaging efforts, corrections for contributing drainage areas and elevation, and
correlation with long --term local precipitation records, the following hydrographs have been developed for
the three lower gaging sites (Figure 4.6). The gaged data was adjusted to the Alternative 4 diversion site
to provide 365 estimated average daily flows used in the energy model computations. The average
monthly flows corresponding to the data are shown below in Table 4.8.
Figure 4.6 - Hydrographs showing average daily flows at the three lower gage sites.
Pyramid Creek ------- EFPyrairidCreek just above confluence
ley Creek below reservoir
400.00 FyrarridGreek atTiidewater
350.00 '
300.00 1 1II
250.00 1
i m 200.00
i m } f I}I I
� 150.00 t1
100.00
50.00
0.00
c 5 rn rn n a U r; a L) c) c)
@ @ tG 97 al Q a A @ @ 7 7
r N M N f; d N T 0 5 76 o6 N !aO c7 ui r 4 O. N �f7 .-
N N N NM
N r4 N
Date
LOCHER INTERESTS, LTD. PAGE 4.13 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Table 4.8 - Average monthly inflow to the Alternative 4 diversion site.
Given an average annual discharge of 13.6 cfs, the unit discharge expected from the project drainage
basin (5.1 sq mi) is 2.67 cfsm.
4.5.5.4 Flow Duration Curves
Flow duration computations were calculated for exceedence probabilities for various percentages of the
total days in the record, irrespective of season of occurrence of such flows. The flow duration curve is
shown below (Table 4.9).
As proposed, the project has a nominal rated discharge of 17.8 cfs. This flow has the probability of
exceedence of 36%. The minimum discharge to generate power (8 cfs) and the maximum allowable
discharge (22 cfs) have a probabilities of exceedence of 63% and 28% respectively.
LOCHER INTERESTS, LTD. PAGE 4.14 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE 11
I
Table 4.9 - Average daily discharge associated with a given probability of exceedence.
! 95
0.0
90
0.0
85
1.2
80
2.7
75
4.5
70
5.9
65
7.6
60
8.9
55
10.6
50
12.2
45
13.3
' 40
15.3
' 35
18.2
30
21.1
25
23.7
20
26.7
15
27.9
10
28.4
5
28.7
Figure 4.7 - Flow duration curve for the selected alternative for hydroelectric power development.
Unalaska
Pyramid Creek
Discharge (cfs)
CO o 0 O M O O c@ n M N M
"*: r' M m SD CA N N (R n7 C'J W "r Ln r L0 O ;r coo
Cn co W r- co m ao ui m r o u� co cD c� o a
1 N N N N N N N r r r aj ti ff7 �' c'7 r p Q p
t'
R 0.01
,Q
L
0.001
_. }
4.5.6 Description of Alternatives and Proposed Project Features
In total, five different alternatives for project development were considered. Four alternatives were carried
to completion; a fifth alternative was deemed unfeasible out -of -hand because its perceived incremental
power benefits above the other alternatives appeared to be low compared with the additional scope of
LOCHER INTERESTS, LTD. PAGE 4.15 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE Il
construction required. A further description of each of the alternatives is covered under paragraph 4.4
above and in Appendix B3. The selected alternative (Alternative 4) is described in more detail below.
4.5.6.1 Diversion Structure
A new diversion is not required for this development, as the existing Icy Creek Dam serves to divert water
into an existing water supply pipeline.
4.5.6.2 Penstock
The first 6,000 ft of 'penstock" would be the existing 24-in ductile iron, water supply pipeline. The pipeline
has installed capacity to convey additional water to the chlorination building where a new penstock would
-� tap into the existing pipeline. The new penstock would be buried along its length from the chlorination
building and continue northerly for about 1,200 ft and then approximately westerly for another 1,300 ft.
The last 1,100 ft of the penstock would drop about 320 ft to the powerhouse situated on the right bank of
Pyramid Creek near tidewater.
1 Test pit logs were made available which indicate that silty sands and gravels are evident, generally, to
depths of 0 to 10 ft below grade before competent bedrock is found. Therefore, bedrock may be
encountered while trenching for the penstock which may require blasting. It is also possible that small
rocks to larger boulders may be encountered during excavation. We have assumed that all of the material
excavated from the trench may be used for backfill, supplemented with locally available stockpiled
materials. It is expected that the entire penstock could be excavated with a track hoe with a 2 cubic yard
bucket.
We examined penstock diameters for a range of turbine sizes from 100 to 800 kW. Typically, penstock
sizes are optimized taking into account penstock procurement and construction costs, pipe friction
headlosses, and the variation in energy with a subsequent varying net head. Our initial studies, though
not detailed for this phase, indicated that there is a substantial difference in energy produced for penstock
sizes ranging from 18 to 30 in (see Figure 4.8), with a 24-in diameter penstock being optimal for a 600 kW
plant.
Several materials may be appropriate to be considered for the penstock pipe, depending on internal
pressure, including high density polyethylene (HDPE), ductile iron, and steel.
We have assumed that steel pipe would be used. The penstock would be designed for an operating
pressure of 220 psi plus a minor pressure rise, considering a gross head of 195 ft. The steel pipe would
have bell and spigot, rubber gasketed joints, an epoxy coating on the inside, and tape wrap on the outside.
The penstock route has one high and one low point along its length. It would be expected that at these
points, air -vacuum valves and blow -off valves would be located for protection and draining of the
penstock, respectively.
4.5.6.3 Powerhouse
The powerhouse would be situated on the right bank of Pyramid Creek near its mouth at tidewater, at
about elevation 20. A powerhouse would house the turbine, generator, controls, switchgear, and station
service equipment. The powerhouse should be constructed so as to be vandal resistant, of the pre-
engineered steel type, with heavy steel doors and no windows. The powerhouse would obtain its power
T from that generated by the equipment or from the grid, if the plant is down for service or low flows. The
11 powerhouse would be heated to prevent freezing or condensation, and ventilated to prevent overheating
of the equipment.
LOCHER INTERESTS, LTD. PAGE 4.16 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
The floor of the powerhouse would be of reinforced concrete, with embedded parts for the turbine and
generator. Below the floor slab, the turbine will exhaust its flow into a flume which conveys water away
from the powerhouse. The flume would transition to a corrugated metal pipe or open channel to convey
water back to the creek.
The powerhouse will be unmanned, meaning that the generating equipment would have adequate controls
to allow it to operate and adjust itself without the attendance of an operator_ Daily visits to the plant are
prudent to check security and provide routine maintenance. It is possible and prudent to allow remote
control and monitoring of the plant via telephone and modem to City offices. Remote monitoring and
control functions would include the capability for remotely starting and stopping the unit.
4.5.6.4 Turbine and Generator
Turbines which can be used for this site include both Pelton or Turgo impulse types and Francis types.
For our analysis, we have assumed use of a 600 kW Pelton turbine (see Section 4.5.7.1 for additional
discussion of turbine size selection).
The selected unit would have a steel housing, three jets, and a stainless steel runner approximately 26
inches in diameter. The needles would be motor actuated by DC power. Depending on supplier, the
turbine generator shaft may be either horizontal or vertically oriented.
The generator will be a 480 volt induction type, relying on the C4's electrical grid for excitation. The
controls will allow local manual or automatic operation of the generating unit.
4.5.6.5 Switchyards and Transmission Lines
The substation would consist of a pad mounted transformer, cable connections to the generator circuit
breaker and the overhead transmission line, and a grounding grid. The oil filled, 750 kVA pad -mount type
transformer would include internal primary fuses and switch. The transformer would step up the 480 volt
3-phase generator output to the required 12,470 volt 3-phase transmission line voltage (assumed). The
generator circuit breaker would be cable connected to the low side of the transformer. The high side of
the transformer would be connected to the buried transmission line. The transmission line termination
would be through a gang operated disconnect switch. Surge arresters would also be furnished at the
transmission line termination for protection of the cable connection and transformer. A copper ground grid
would be installed around the transformer pad and tied into the powerhouse grounding system.
The buried transmission line (T-line) would extend about 700 ft and connect the power plant substation to
the existing distribution line located adjacent to Captains Bay Road. The T-line would be 15 kV, 3
conductor copper cable in a 4-in PVC conduit. The new T-line would be connected to the existing line
through a vault -mounted isolating switch.
4.5.6.6 Access Roads
Based on the findings of recent project in the area, sands and gravels lie below the ground surface. We
have assumed that such material would make suitable road beds and surfacing. For the minor road work
necessary to gain access to the power plants, they could be constructed without great expense. We have
assumed that access to the powerhouse site, near the mouth of Pyramid Creek, is partially established
because there is an existing abandoned building nearby. We have assumed that any abandoned drives
or roads will be improved to the powerhouse location.
LOCHER INTERESTS, LTD, PAGE 4.17 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE Il
4.5.7 Energy and Capacity
As explained in paragraph 2.4.1, a computer model was developed to compute average monthly and
annual energy produced by a theoretical project installation. The specific input values used to compute
energy include average daily flows (365 data points), gross head, penstock size, water system
conveyance loss coefficients, selected turbine capacity, estimated turbine efficiency curve, and generator
and transformer efficiencies. Results of the model output are attached as Appendix A2.
4.5.7.1 Installed Capacity
In sizing the unit, turbine sizes from 100 to 800 kW were examined. The optimum installation with a new
24-in penstock appears to be 600 kW (see Figure 4.8 below). With this installation, the City's installed
capacity would be increased by 8% from 7,500 kW to 8,100 kW. The peak demand during the past five
years was 5,730 kW as indicated in Table 4.5.
Figure 4.8 - Annual energy output vs. installed unit size (single unit installations).
3,000,000
2,500,000
s
_a 2,000,000
3
0
`m
C
w 1,500,000
1,000.000
500,000
Turbine Size vs. Annual Energy Output
30"'Penstock
I I ,
-
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ J _ _ _ _ _ _
Penstock
Zot
l 18" Penstock
+ I I I I I
f I
100 200 300 400 500 600 700 800
Turbine S", kW
4.5.7.2 Firm Capacity
In re-evaluating the installed capacity and the annual energy produced, averaged daily flows were used.
This has the effect of producing an average annual output that is reasonable for this stage of study, but,
due to averaging ranges of flows, loses the effects of extreme high and low instantaneous events on
energy production over the period of study. To determine firm capacity, monthly low events (and power
produced from the low events) need to be compared to monthly instantaneous requirements. This is
beyond the scope of this study. However, even using average daily flows, every month except for June,
July, and November had days of no output or energy production. During those months, the minimum
output was 632 kW (June), 344 kW (July), and 276 kW (November).
LOCHER INTERESTS, LTD. PAGE 4.18 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE It
4.5.7.3 Average Annual Output
The average annual energy computation for a 600 kW plant is 2,570,033 kWh. The model computations
performed for this report include estimated efficiencies of the turbine (variable), and assumed fixed
efficiencies for the generator (93%) and transformer (98%). These computations assumed that energy is
generated every day that there is flow capable of operating the turbine. During this study, using average
annual flows, the plant generated electricity 61% of the time. In reality, it is likely that the equipment may
experience outages and may be taken off line for annual maintenance. Therefore, we think it prudent to
reduce any theoretical annual energy computation by 3%.
The computer model is capable of reducing the flow used for generation due to requirements for instream
flows, though the licensing process is not far along enough to enable determining whether an instream
flow reservation would be required from the diversion. For use in our studies, we assumed that an
instream flow would not be required because there is a substantial drainage basin below the diversion
point at Icy Creek Dam. Further, outfall from the powerhouse could likely be located so as to return
virtually all of the water to the section of stream which provides salmon spawning habitat. However, if a
required instream flow is mandated, power production would be reduced. In that case, the powerplant
outfall could likely be located so that most, if not all, the spawning habitat in the tidewater portion of
Pyramid Creek remains essentially unaffected.
4.5.7.4 Average Monthly Output
Based on a 600 kW unit, the following monthly average energies were computed without reduction for
down time and are indicated in Table 4.10 and Figure 4.9 below:
Table 4.10 Icy Creels monthly total average generation for a 600 kW installation.
0.
January
156,399
34.9
52
February
100,077
24.7
36
March
168,570
37.6
48
April
157,443
36.3
47
May
273,069
61.0
74
June
386,303
88.9
100
July
405,513
90.5
100
August
145,503
32.5
42
September
54,856
12.7
17
October
274,131
61.2
90
November
359,068
82.8
100
December
90,100
20.1
29
LOCHER INTERESTS, LTD. PAGE 4.19 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Figure 4.10 - Icy Creek monthly total average generation for a 600 kW installation.
Average Monthly Energy Output
450,000 _
400,000 -
350,000 —
300,000 -
250,000 _
" 200,000 _
150,000
100,000 -
50,000
0
c L a c rn a > U
Q a� O o aD
LL-Q cn z ❑
Month
4.5.8 Quantity Estimates for Development
Project specific topographic mapping with 10-foot contour intervals was made available for this site.
Elevations of the intake, penstock alignment, and powerhouse sites were taken from the supplied
topographic map. A review of the ESl and Polarconsult project feature layouts were made and
independent layouts performed for the purpose of developing feasibility level quantity estimates. Activity
durations were estimated based on conversations with contractors and reference materials.
4.5.9 Project Cost Estimate
Cost estimates were prepared estimating costs of labor, materials, equipment, and shipping for each work
item. The intent was to account for the various labor and productivity rates and to ensure that shipping
costs were adequately accounted for each item. This makes the appearance of perhaps greater detail
than would normally be warranted for a feasibility level cost estimate. The costs and productivity rates
were based on those found in Mean's estimating guides, adjusted by conversations with contractors
accustomed to working in Alaska, and conversations with various suppliers. Lump sum estimated
installed costs were divided into labor, materials, equipment, and shipping based on a reasonable split of
work.
LOCHER INTERESTS, LTD. PAGE 4.20 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Polarconsult explained in their 1995 report for Old Harbor, and referenced in their 1994 report for Icy
Creek, that they used a "Force Account" method of construction where local labor was used to the extent
possible to reduce costs. They used laborers with a cost of $20 per hour which includes wages and
taxes, except for a minimum amount of skilled labor to install and test the generating unit. We feel such
an approach is reasonable. However, it is inevitable that more skilled outside labor will be required for
construction of a hydroelectric power project, and this will require transportation costs, per diem, and
likely, prevailing wages.
For this study, two cost estimates were prepared, one based on a conventional contractor constructed
project and one based on the force account method. For the estimate based on contractor construction,
prevailing wages, based on State of Alaska's 11/1/97 Laborers' & Mechanics' Minimum Rates of Pay,
were used with multipliers for Worker's Compensation, Social Security taxes, etc., and $70 per day for per
diem. On the force account method lower wages without benefits and per diem for the local, unskilled
laborer positions were used, and a skilled worker was placed with each unskilled crew. However,
production was assumed to be less using IOcal unskilled labor than for skilled labor, which is typical for
standard contracting methods. For skilled labor, prevailing wages plus benefits and per diem were used.
Labor costs for both skill levels were factored upwards for Worker's Compensation, Social Security taxes,
etc.
Costs for materials were based on that required to purchase them in a competitive market, and $0.08 per
pound was used for barge shipping to the Unalaska site. For materials such as fabricated steel items, the
material price per pound would be the away -from -site fabricated price, and the labor quantity would be that
required to install it in the field.
Generating equipment is available from a variety of sources, many of which are foreign. World money
market rates are constantly changing and the level of quality vary, making pricing subject to much
fluctuation. In addition, some vendors are not willing or capable of guaranteeing their equipment as are
the major equipment manufacturers. At the time of this report, only two quotations had been received
from what we consider to be a fully bonafide manufacturer and one from a small vendor.
The cost associated with the electro-mechanical equipment in the Force Account cost estimate included
turbine equipment provided by a small local (northwestern) vendor who supplies equipment without
warranty, whereas the conventional cost estimate includes fully warranted equipment purchased from a
larger and major manufacturer.
Equipment rental were based on Blue Book rates adjusted for various Alaskan regions. Shipping costs
were added to equipment rental costs_ It was assumed that one track hoe would be used for the majority
of the work, as it can be used for earthwork required at the powerhouse, penstock and conduit trenching,
and for the access road to the powerhouse.
JIt was assumed that two separate crews would be required for construction. One crew of four people was
assumed to be required for construction of the penstock. This assumed a hoe operator, two laborers in
the trench, and one spotter. It was assumed that production would be around 500 If of penstock per day.
The other crew was assumed to be constructing the powerhouse, access road, and T-line. We believe
j that it would be possible to construct the project in a single construction season of six months.
Our cost analysis for a standard construction process is $2,177,800 and $1,557,900 for a force account
process. Detailed cost breakdowns are contained in Appendix B2.
For the standard contracting method, we included costs for contractor overhead, profit, insurance, and
bonding and have increased the estimated total construction cost by a 25% contingency allowance, which
is appropriate for this stage of development, as preliminary designs and detailed surveys have not been
LOCHER INTERESTS, LTD. PAGE 4.21 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE 11
performed. We have included reasonable costs for project administration, FERC licensing and permitting,
engineering, and construction management. For the force account method, we assume that the City is not
trying to make a profit and bonding will not be required, therefore, those costs have been eliminated.
4.5.9.1 Capital Replacement Costs
For the purpose of establishing an annual budget, a fund should be established to allow for future
unplanned, unscheduled replacement costs_ Most routine costs will be paid for under the operations and
maintenance (O&M) budget_ Additional unscheduled costs may involve work such as a major turbine
overhaul or a generator rewind. Costs for each could be in the order of $100,000 to $150,000. If it were
assumed that 1.5 events occurred every 25 years, then a simple straight-line replacement cost fund would
require that $9,000 per year be placed in a separate account.
4.5.9.2 Operations and Maintenance Costs
Typically, at this stage of planning, 0&M costs are based on a factor related to the installed capacity. This
does not always provide accurate costs for small plants. In 1994, HydroVision performed a survey of
plant operators to quantify annual O&M costs_ For small single -unit projects, respondents indicated an
average O&M cost of about $38,000; $41,600 escalated at 3% per year to 1997. If a factor for a remote
location in Alaska is used (10 to 20% higher), then a planned O&M expense may be about $48,000 per
year.
4.5.10 Economic and Financial Analysis
The economic assessment of the project has been updated using refined assumptions. In addition, a utility
financial analysis has been used to determine the implications under debt financing of the project for the
Unalaska Electric Utility's cost of service and revenue requirements. The economic analysis is conducted
in real 1997 dollars. The financial analysis is conducted in nominal or current dollars, assuming 3%
inflation.
Economic and financial analyses were performed for both proposed Alternatives 1 and 4
4.5.10.1 Economic Assumptions
3 For Unalaska, real fuel price growth is the only critical economic assumption. With possible low (force
account) or high (contractor) construction costs, there are only six possible cases to consider. The three
real fuel price growth rates are 0.0%, 0.6%, and 1.5%. The force account construction cost is $1,557,900.
The contractor cost is $2,177,800. The real discount rate of 2.91% is derived from the assumed nominal
interest rate of 6% and the assumed inflation rate of 3%. {Note: The exact calculation is
! 0.0291 = (1.0611.03) - 11. The results present dollars discounted back to 1997.
4.5.10.2 Financial Assumptions
1 The project is assumed to be financed by tax-exempt debt at a nominal interest rate of 6.0%. A debt
j issuance cost of 2% of face value is added to the amount of debt issued. The project is assumed to be
constructed in 2001 and to go online on January 1, 2002. All construction outlays are modeled as if they
were made on January 1, 2001. This is a good approximation of the actual procurement pattern, which
might involve procurement and outlays from about July, 2000 through December 2001 in order to achieve
the online date of January 1, 2002.
Two measures of possible financial impact are used. The "accrual basis cost of service" is based on
projected accounting costs. It uses depreciation as an expense and does not consider a need for net
LOCHER INTERESTS, LTD. PAGE 4.22 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
income or "margins" in determining rates. The "cash basis revenue requirement' may be a more accurate
reflection of what a lender would want to see recovered in revenue. It uses debt principal payments
instead of depreciation and includes an allowance for margins equal to 50% of interest, so as to meet an
assumed target for the ratio of (interest + margins)/(interest), or TIER, of 1.5.
Table 4.11 below summarizes the financial assumptions used for Unalaska.
Table 4.11 - Financial assumptions for Unalaska.
Financial arame ers
Nominal Debt Interest Rate
%
6.0%
New e t ssuance Cost
o of face va u
0
Inflaflon Rate
%
0
Target TIER Ratio
antAdditions:
Book Life
0 e t
0 ui
New Diesel
15
100%
0
New Hydro
0
0
other New lant
o
0
4.5.10.3 Economic Analysis
Pyramid Creek Alternative 4: The Pyramid Creek Alternative 4 project has significant positive net
benefits under all plausible assumptions. Under mid -range assumptions about fuel price growth, the
project has a present value of net benefits of about +$1.6 million using the low capital cost, and net
benefits of +$1.0 million using contractor costs. Under the most pessimistic set of assumptions (zero fuel
price growth and high construction cost), the net benefits are still +$0.7 million. Under the most optimistic
assumptions (1.5% fuel price growth and low construction cost), the project has positive net benefits of
about $2.2 million.
Since there are only six possible cases, no probability analysis is needed. Table 4.12 below shows the net
benefits for all six sets of assumptions.
Table 4.12 - Pyramid Creek Alternative 4 net benefits.
mmary
as a Function
Net Benefits
of Hydro
High (Contractor) Construction Cost:
Low Fuel Price Growth 0.0%
847,761
Mid 0.5%
1,120,661
High 1.5%
1,773,415
Low (Force Account) Construction Cost:
Low Fuel Price Growth 0.0% 1,400,407
Mid 0.5% 1,673,307
High 1.5% 2,326,061
These results assume no restrictions on minimum streamflow. The effects of these restrictions are
discussed elsewhere in the text.
LOCHER INTERESTS, LTD. PAGE 4.23 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Pyramid Creek Alternative 1: This project only produces net benefits under the low construction cost
assumption and positive fuel price escalation. Table 4.13 below summarizes the results.
Table 4.13 - Pyramid Creek Alternative 1 net benefits.
Summary of NeiBenefits as a Function ot Fuelrice Growth
(Unalaska erns rve owerRecovery)
Wet Benefits
ot Hydro
High (Contractor) Construction ost:
ow Fuel Price Growth
0.0%
(107,424)
a
High
. o
i7,57
LOW(ForceAccount) ConstructionCost:
Low Fuel Price Growth
0.0%
,
Mid
o
i9
,
4.5.10.4 Financial and Utility Rate Impact Analysis
Pyramid Creek Alternative 4: Under mid -range assumptions and contractor costs, the City of Unalaska's
cost of service (accrual basis) would increase by about $59,000 during the first years of hydropower
operation. This represents a 1.1% increase, or about 0.2 cents per kWh. The cost of service with
hydropower would be lower than without hydropower beginning in 2009.
Cash basis revenue requirements would increase by slightly more (about 1.5%, or 0.3 cents per kWh) in
2002, and become lower than those without hydropower in the year 2013.
Table 4.14 below shows the difference in cost of service for all six combinations of construction cost and
fuel price escalation. The main conclusion to note is that with the low (force account basis) construction
cost, the cost of service drops immediately under all fuel price scenarios, because the first year fuel
savings exceed the first year sum of hydropower depreciation plus interest.
Table 4.14 - Summary of accrual basis cost of service impacts of hydropower.
Pyramid inancia esu s
ummary:
Increase (Decrease)
in Accrual Basis Cost of Service due to Hydro
(based on depreciation plus interest and excludes margins)
Current Dollars
% Chancie
from Diesel -only
2002
2005
2010
2020
2030
2002 2005 2010 2020 2030
Contractor cost
Fuel growth: low
63,162
41,306 (1,203) (116,062)
(289,307)
1.1%
0.6%
0.00,1,
-0.9%
0.0%
mid
59,101
34,152 (14,849) (149,340)
(355,133)
1.1%
0.5%
-0.2%
-1.1%
0.0%
high
50,734
19,078 (44,707) (227,866)
(522,752)
0.9%
0.3%
-0.5%
-1.5%
0.0%
Force account cost
Fuel growth: low
(2,254)
(22,288) (60,953) (163,784)
(315,490)
0.09/6
-0.3%
-0.7%
-1.2%
0.0%
mid
(6,315)
(29,441) (74,599) (197,062)
(381,316)
-0.1%
-0.5%
-0.9%
-1.4%
0.0%
high
(14,682)
(44,516) (104,456) (275,598)
(548,935)
-0.3%
-0.7%
-1.2%
-1.8%
0.0%
LOCHER INTERESTS, LTD. PAGE 4.24 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE Il
Combined Alternatives 4 and 1: Alternative 1 adds an additional one half of one percentage point to the
initial increase; under midrange assumptions the cost of service rises by 1.6% (viz. 1.1 % for Alternative 4
alone) and the cash basis revenue requirement rises by 2.2% (viz. 1.5% for Alternative 4 alone).
4.5.10.5 Break-even Analysis and Discussion of Economic]Financial Viability
No specific breakeven analysis seems useful for Alternative 4 because the net benefits are substantial
and positive for all plausible sets of assumptions.
In summary, Pyramid Creek Alternative 4 appears to be a very solid project. It does not depend for
economic feasibility on load growth or fuel price increases or any presumed capacity deferral benefits. Air
quality benefits are additional to those considered here.
Pyramid Creek Alternative 1 is only marginally economic. The projecfs output is much lower than the
amount assumed for the Phase I analysis. It is this drop in output with no corresponding decline in
construction cost that accounts for the difference between this analysis and the generally positive
economics found during Phase I.
4.5.11 Regulatory and Permitting Issues
Major environmental issues to be addressed for this project include fisheries impacts associated with
reductions in flow below the Icy Reservoir diversion structure and potential environmental waste problems
encountered in the lower floodplain area which has been used as an industrial storagellaydown area and
an unauthorized dumping ground for some time. Crowley Marine currently has several large fuel storage
tanks located along the left bank of the stream. Whether past use of this area has resulted in
contamination of the soils or groundwater is an issue which will require immediate attention in the
feasibility level investigation phase for this development.
Past investigators have suggested that a power development on Pyramid Creek could be developed
without a FERC license (Energy Stream, 1985b). However, Ounalaska Native Corporation (ONC) land
ownership, the presence of anadramous fish stocks, and possible waste issues are such that little could
be gained by attempting to develop this project outside of the FERC process. In fact, Federal coordination
of the process within the regulations of the FERC process will very likely be beneficial to the process.
4.5.11.1 Land
The City of Unalaska owns all of Section 34, Township 73 South, Range 118 West, as well as a 200 ft
wide corridor along Icy Creek downstream to the water treatment plant. This land is designated as the
City of Unalaska watershed. The remaining lands in the basin above the water treatment plant are owned
by the ONG (Exhibit 155). ONG also owns lands along Pyramid Creek in the lower canyon and along the
flood plain, in Sections 16 and 21, where it drops to tidewater. In the lower tidewater portion of the stream,
in Section 16, the stream flows primarily through two privately owned parcels of land, including the
` Crowley Marine Services industrial site and a 4.87 acre lot owned by a local Unalaska resident who
reportedly plans to construct a workshop and family housing on this land. Development of the proposed
project will require use of portions of the lands held by all three of these owners. The majority of the
penstock alignment falls on ONG land; the powerhouse and tailrace would be located primarily on Crowley
Marine Services lands; and access to the powerhouse would be mainly across the private local resident's
parcel.
LOCHER INTERESTS, LTD. PAGE 4.25 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
4.5.12 Environmental Conditions
Much of the Pyramid Creek Basin is a part of the City of Unalaska's protected watershed, and has
controlled access and use restrictions. Thus, aside from developments associated with the water supply
system itself (access road, reservoirs, pipeline and water treatment plant/water tank) the middle and upper
basins are in essentially pristine conditions. The area below the water treatment plant has the remnants
(foundation slabs and walls) of military hospital facilities present along the road and the extreme lower
section of the stream, near tidewater, is heavily used as a part of a laydown area/junk-yard associated
with the Crowley Marine Services property on the left bank. The lower stream has been bermed off along
the left bank near the Crowley Marine Services property. In addition, portions of the canyon just below the
first major fails apparently have been used as an uncontrolled dump area in the past and abandoned
automobiles and other materials are strewn along this section of stream.
4.5.12.1 Terrestrial Flora/Fauna
Flora: Most of the Pyramid Creek Basin is tundra, comprised of areas of low tundra marsh (dominated by
sedges, reedgrass, bog blueberry, horsetail and rushes) and extensive areas of the drier, more common
upland tundra habitat (dominated by crowberry, willow, lichens, mosses, and sedges). Dwarf willows and
alder are common in the upland areas, especially along the stream courses.
' Except for the road corridor and areas around the two diversion structures and water treatment plant, very
little of the basin vegetation has been disturbed. The recently constructed road between Icy Creek
Diversion and Icy Lake Diversion has been reseeded along much of its length. These reseeded areas are
still only partially vegetated. In other areas, however, the original vegetative mat was retained and
replaced over disturbed areas after recent construction projects were completed. These latter areas show
an advanced stage of recovery, compared to the areas which were reseeded.
Fauna: Neither the earlier hydroelectric power evaluations nor the studies done for the Icy Lake Diversion
Project or Icy Creek Diversion upgrade included detailed biological resource studies. The USACOE
(1984) feasibility study did include a limited environmental assessment of both the Pyramid Creek and
Shaishnikof River developments, however. This assessment relied primarily on secondary sources, with
supplemental observations provided by a field reconnaissance conducted by Fish and Wildlife Service and
USACOE biologists. The discussion provided below is based on that report, supplemented by
observations made during Locher's October 1997 field reconnaissance.
- Mammals: As is true of the Aleutians in general, the terrestrial fauna of Unalaska is limited to a few,
generally small species. The red fox is the largest mammal of the area, and one of the principal
predators. Arctic ground squirrels, an introduced species, appear to be abundant throughout the basin.
The European hare, also an introduced species, is known to be present on Unalaska. These three
species, along with shrews, collared lemmings, voles, and the introduced Norwegian rat, probably
comprise the bulk of the mammalian fauna of the area.
Birds: Avifauna on Unalaska, with the exception of the very large variety of coastal and marine species,
which do not commonly frequent the project area, is limited. The USACOE (1984) reported that 14
species of birds were sighted in the nearby Shaishnikof Valley and it is likely that the same assemblage
occurs in Pyramid Creek Basin. Bald eagles, ravens, and dippers were observed to be common during
the October 1997 field reconnaissance. Lapland longspur, common merganser, common snipe, belted
kingfisher, common redpoll and rack ptarmigan are also likely residents of the basin. A few other species
of birds, mostly small species such as song sparrow, winter wren, and snow bunting also likely exist in the
area.
LOCHER INTERESTS, LTD. PAGE 4.26 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
The steep canyon area below the water treatment plant may provide nesting habitat for raptors. The
short -eared owl, rough -legged hawk, bald eagle, marsh hawk, gyrfalcon and Peale's peregrine falcon are
all reported to be residents of Unalaska. Except for bald eagles, no other raptors were sighted during the
1997 field reconnaissance. A cursory examination did not reveal any evidence of their use of the canyon
cliff walls.
Project construction will require the disturbance of slightly over one acre of land for the installation of the
penstock. A corridor of variable width (ca 20 feet wide at a maximum) will be disturbed along the
approximately 3,500 foot long penstock alignment, between the existing chlorination plant and the site of
the powerhouse, near elevation 20, on the right bank of Pyramid Creek. The vegetative mat along a
portion of this corridor will be removed and, using a backhoe, a trench will be dug to bury the penstock.
Additional areas of vegetation along this alignment will be disturbed by movement of equipment along the
corridor, stockpiling and removal of sections of penstock, and movement and placement of backfill
material in the trench.
The surface vegetation to be removed can be set aside and replaced after construction is completed, as
was done along portions of the recently constructed access road to the Icy Lake Diversion. This should
hasten the revegetation of the area disturbed for penstock placement, as observed along the access road.
Some areas will require reseeding with an appropriate seed mix to establish ground cover as quickly as
possible and protect against erosion. In addition, some sort of permanent access trail along the penstock
alignment likely will be required, to allow future monitoring and maintenance. This trail would be narrower
than the 20 ft wide (maximum) zone of initial disturbance, perhaps on the order of a 10 ft wide prism.
Thus, approximately one acre of terrestrial vegetation will be disturbed along the penstock alignment
during project construction, of which approximately 50% will be revegetated, using as much of the original
vegetative mat as possible, and 50% will remain permanently disturbed as part of the project penstock
access trail. An additional area, probably less than one acre, will be permanently disturbed in the lower
Pyramid Creek flood plain for construction of the access road, power house, and tailrace channel. Much
of this land is already significantly disturbed by past use as industrial area and as a storagellaydown area
and unapproved dump site.
4.5.12.2 Fisheries
J Previous investigations (USACOE, 1984) reported that the presence of culverts at the mouth of Pyramid
Creek, combined with installation of the water treatment plant had nearly terminated a run of pink salmon
in lower Pyramid Creek. This run has apparently partially recovered, however, and according to the
ADF&G Catalog of Waters Important for Spawning, Rearing, or Migration of Anadromous Fish (1994) as
well as information supplied by ADF&G (W. Dozelal, personal communication) the lower section of
Pyramid Creek, from tidewater upstream about 2,300 feet to the first falls, provides habitat for coho and
pink salmon, as well as sea run dolly varden. Resident populations of dolly varden exist above the canyon
and falls as far upstream as the falls upstream of Icy Creek Reservoir, as well as in the East Fork of
Pyramid Creek, but apparently do not reach the Icy Lake Reservoir area (W. Dozelal, personal
communication).
The proposed development would impact both resident dolly varden populations in Pyramid Creek below
icy Creek Reservoir and anadromous populations of pink salmon, coho salmon and dolly varden which
utilize the lower 2,300 feet of Pyramid Creek, from tidewater outfall up to the first falls in the canyon.
Pyramid Creek between the Icy Creek Reservoir and the outfall of the power house will have substantially
reduced flows due to diversion of water into the penstock for power production. This reduction in flow will
be mitigated to some degree by the intervening flows entering the creek below the reservoir, including
contributions from the East Fork of Pyramid Creek. However, significant reductions will occur in all areas
of habitat for resident dolly varden from the Icy Creek reservoir downstream, and (depending on final
LOCHER INTERESTS, LTD, PAGE 4.27 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
location of the powerhouse outfall) in approximately 50% of the 2,300 foot section of lower Pyramid Creek
(from the first falls downstream to the powerhouse tailrace outfall near elevation 20). A requirement for
maintaining some minimum flow release at the Icy Creek Reservoir would reduce the level of impact, as
shown in Table 4.15 below. However, this would impact the economic viability of the project.
Table 4.15 - Predicted Reduction in Average Monthly Discharge in Pyramid Creek, From Icy Creek
Reservoir to Powerhouse Tailrace Outfall, With and Without 3 cfs Minimum Release.
F
Jan
BefowMt
Fork confluencelmpa�sole
withoutWfth
27 39
Fit
35
-rs t
wit
51
Feb
9 I 11
42
53
Mar
14 18
23
35
Apr
26 41
25
37
May
27 38
26
35
Jun f
1 1
22
25
Jul
27 32
52
59
Aug
17 ; 25
39
52
Sep
7 18
10
21
I Oct
39 j 51
48
63
Nov j
42 1 52
73
88 i
Dec f
19 1 44
26
49
The above percentages are based on average flows and do not completely represent the range of flow
reductions which would occur. An analysis of instantaneous flows, which is beyond the scope of this
study, likely would result in periods when the project's effects on flow are both higher than and lower than
the percent reductions shown above. To determine the actual effect of flow reductions on fish
populations, detailed instream flow studies will be required as a part of licensing and permitting studies for
this development. However, given the extent of the reduction without a minimum flow release
requirement, it is likely that impacts will be considered significant and some type of fisheries mitigation
program will be required. This could include a requirement for seasonally variable minimum flow releases
from Icy Reservoir, physical enhancement of critical areas of the stream, off -site mitigation, or some
combination of one or more of these measures. Without detailed fisheries and instream flow analyses it is
impossible to predict which measures would be judged sufficient. Preliminary analysis indicates that a
requirement of 3 cfs minimum flow reservation at Icy Reservoir could be met without seriously effecting
the projects economic viability (see subsection 4.5.13 for a discussion of reduced flow available for
hydropower development).
For project evaluation purposes, we have also included money for physical stream enhancement of
Pyramid Creek, as well as money for design and installation of fish protection features into the
powerhouse outlet within total project cost estimates. Possible stream enhancement activities to be
implemented as a part of a fisheries mitigation plan could include placement of spawning gravels, both in
the existing stream and in the tailrace channel, cleaning of existing gravels in areas where sediment
deposition has occurred, improvement of access into the stream (at the culverts), and/or creation or
improvement of side channel habitat for coho rearing.
4.5.12.3 Cultural Resources
The Army Corps report (USACOE, 1984) included results of a cultural resources reconnaissance for the
Pyramid Creek Project. Results of this survey indicated that it was highly unlikely that a development in
LOCHER INTERESTS, LTD. PAGE 4.28 JANUARY 09, 1998
1
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
the middle and upper basin would have an impact on prehistoric sites, as Native populations concentrated
their activities along the biologically productive coastal habitat. However, early reports of prehistoric sites
near the mouth of Pyramid Creek are known. Determination of the exact location and condition of these
sites was not possible at the time of the cultural resource evaluation, due to the use of this area for
industrial purposes and for general storage_ It was recommended, however, that a cultural survey be
done in the area if a powerhouse or other facility is to be developed along the lower, tidewater section of
the creek.
At the time of Locher's 1997 field reconnaissance, this area was found as current use for storage and has
been extensively altered by the construction of large fuel storage tanks, with associated spill containment
features, as well as by construction of a small section of rock berm along the right bank of the stream and
use of the lower floodplain as a storage yardllaydown area. There also are noticeable remnants of old
structures in the lower floodplain which may or may not have cultural significance.
The existence of the remnants of the World War II hospital buildings, located along the road to the water
treatment plant, was also noted in the reconnaissance report (USACOE, 1984) with a recommendation
that care be taken to avoid damage to these remains.
The proposed development will require disturbance of the lower flood plain area of Pyramid Creek, for
construction of the powerhouse, as well as disturbance of a corridor approximately 2,500 feet in length
from the existing chlorination plant down through the lower canyon to the floodplain for the new penstock.
A site specific cultural resource survey will be required as a part of the feasibility level investigations for
this development. It is unlikely that any cultural or historic resources exist along the penstock alignment,
as most use of the area was concentrated at or near sea level. Further, any sites encountered likely could
+ be avoided relatively simply by realignment of the penstock. Cultural resources are more likely to exist in
areas planned for access to the powerhouse, at the powerhouse proper, and in the tailrace area. Should
cultural resource material or sites of potential significance be discovered in these areas, recovery by
excavation, protection by burial, or avoidance by re -siting of project features are all possible means to
mitigate or avoid impacts_
4.5.13 Effect of Competing Water Use Withdrawals on Pyramid Creek Alternative 4
Existing data for daily average water withdrawal for City supply from Icy Creek has been determined from
seven years of water production logs recorded at the reservoir (1991-1997). Maximum daily demand
peaks at about 7 mgd, except during one instance in June of 1992 which required 8.5 mgd to meet City
requirements.
LOCHER INTERESTS, LTD, PAGE 4,29 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Figure 4.10 -Water supply withdrawal measured through treatment plant for City of Unalaska.
Water Production through Pyramid Plant (mgd)
1991-1997
AVERAGE DAILY DB/ANDI
9.0
(MGD)
I
-. MAXIMUM DAILY DEMAND
8 0
I
I
(MGD)
7.0
,
�
r
6.01
2,0
i
I 1.0
0.0
.a).(a
=
�i Q
Q
? ? ?
07
Q
CIJ fn O
a
Z Z
r
c0 V
N r� N N
N
N 5y
a5
T N -
N M o N
—
In general, for the period 1991-1997, maximum daily demand corresponds with maximum power demands
during pollock processing seasons- Monthly water supply demands in February and September are 90%
and 55% greater than the annual average demand of 2.14 mgd (3.3 cfs). In 1996, the annual average
demand was 1.7 mgd. For a population of 4,087 recorded the same year, the 1996 per capita use was
418 gallcapiday.
Figure 4.11 - Average monthly water demand for the City of Unalaska.
AVERAGE MONTHLY D;3MND (MGD)
4.50
4.97
4.00 .
3.50
3.33
3.00
2.74
2-5D
1.95 1,86
2.00
1.74
1.55
1.33 1-42
1.50
1.00
0,50
0.00
(2�10 R U .� N C N N N SU
o
> > m Q E E E
n. O 7o L)
a)ID
Z O
LOCHER INTERESTS, LTD. PAGE 4.30 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Our power output and economic analyses of the Pyramid Creek Project assume that the City's water use
from the Icy Creek Reservoir is on the order of 1.7 mg per day based upon recent (1996) production data.
This represents current water use levels. However, it is also recognized that the water use requirements
could increase substantially in the future, thus impacting the hydroelectric project's ability to produce
power. Further, as discussed in the environmental evaluation section, it is possible that a condition of
permitting for the project could require provision of a minimum flow release at the Icy Creek Reservoir, to
protect resident dolly varden populations in the creek below the diversion dam, as well as pink and coho
salmon spawning habitat in the lower section of the creek below the falls, but above the powerhouse
tailrace outfall. Such a fisheries release requirement would also effect the power output potential of the
project.
To evaluate the potential impacts of either or both of the above competing water use requirements on the
project, an analysis has been done on the power output from the project under a combination of minimum
flow requirement scenarios, assuming that water use by the City had doubled. Concurrently, an analysis
was done of the effect of the resulting reduced power output on the project's net present value.
Figure 4.12 below summarizes the results of these analyses.
Figure 4.12 - Effect of reduced power output on net present value (NPV) for Pyramid Creek Project
Pyramid Creek Project: Effect of Reduced Power output on NPV
3.00
2.50
j
2.00
d
x
3
Y 1.50
_a
O
1.00
0.50
0.00
0 0.25 0.5 0.75 1 1.25 1.5 1.75 2
Net Present Value
As shown, combinations of increased City water use and minimum flow requirements which reduce power
j output to about 1,115,000 kWh/year are required to reduce the project's Net Present Value (NPV) to zero.
However, hydroelectric power output analysis indicates that a doubling of the City's water supply demand
(to about 32 mg per day) combined with a minimum flow requirement for fisheries of 5 cfs, year round,
a only reduces power output to 1,470,000 kWh/year. At that output, the project would still have a positive
LOCHER INTERESTS, LTD. PAGE 4,31 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE1I
NPV of approximately $360,000. Assuming that the City continues to grow at the same rate as has been
the case since 1990, and assuming that water demand per capita remains the same, water use
requirements for Unalaska will not double until the year 2025. Further, this probably represents a
conservatively high estimate of future water use as the per capita water consumption in Unalaska
currently is skewed towards the high range when compared to most other cities, due to the very nigh
water use requirements of the fish processing industry. Therefore, a doubling of population with
concurrent doubling of water use assumes that all future growth is related to an expansion of the fish
processing industry (with no attempts to improve water use practices by the processors). Given the past
history of fish stock responses to intensive fisheries, along with probable industry response to increased
costs of water, which likely would occur should demand grow at this rate, this is not a likely scenario.
Furthermore, a minimum flow release requirement of 5 cfs, year round, is considered to be in excess of
what might reasonably be required to provide mitigation for the existing fisheries resources of the Pyramid
Creek.
LOCHER INTERESTS, LTD. PAGE 4.32 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE it
' 5. REFERENCES
Alaska Department of Fish & Game. 1994. Catalog of Waters Important for Spawning, Rearing, or
Migration of Anadromous Fish.
Alaska Department of Labor. 1997. Laborers' and Mechanics' Minimum Rates of Pay.
Alaska Department of Natural Resources, August, 1996. Streamflow Data Report, Pyramid Creek
Drainage Basin; Unalaska, AK (Draft).
Alaska Department of Natural Resources, October, 1996. Old Harbor Stream Gaging Project: Final
Report.
AVEC, 1997a. Old Harbor Project, FERC Project #11561-000, Apd] 10, 1997 Progress Report. Alaska
Village Electric Cooperative, Inc. and Polarconsult.
AVEC. 1997b. Old Harbor Project, FERC Project #11561-000, September 19, 1997 Progress Report,
Alaska Village Electric Cooperative, Inc. and Polarconsult.
Barnes, V_G. and Smith, R.B. 1997. Brown bear population assessment on the Shearwater Peninsula
and Kiliuda Bay Areas, Kodiak Island, Alaska. Final Report, USFWS_
Berns, Rick. 1997. Village of Old Harbor. Personal Communication.
Blackett, R.B. 1992. Salmon Returns, Spawner Distribution, and Pre -emergent Fry Survival in the Terror
and Kizhuyak Rivers, 1982-1990. RFB Aquatech, Inc.
CHZM-Hill. 1981. Reconnaissance Study of Energy Requirements and Alternatives for Akhiok, King
Cove, Larson Bay, Old Harbor, Ouzinkie, and Sand Point. Alaska Power Authority.
Dowl Engineers, Tudor Engineering Company and Dryden and LaRue. 1982. Feasibility Study for Old
Harbor Hydroelectric Project. Volume C; Final Report. Alaska Power Authority.
Dozelal, Wayne. 1997. Alaska Department of Fish and Game_ Personal Communication.
Ebasco Services. 1980. Regional Inventory and Reconnaissance Study for Small Hydropower Projects:
Aleutian islands, Alaska Peninsula, Kodiak Island, Alaska. Vols_ 1 and 2. Alaska Power Authority.
Energy Steam Inc. 1985a. Overview; Pyramid Creek Hydroelectric Project.
Energy Steam Inc. 1985b. Petition to the Federal Energy Regulatory Commission for a Declaratory Order
that the Commission Lacks Jurisdiction over the Pyramid Creek Hydroelectric Project, Unalaska, Alaska,
HDR Engineering, Inc. 1995. Unalaska Utilities Improvement Program. Prepared for City of Unalaska,
Department of Public Utilities. Anchorage, AK
HydroVision94, August 1994. Operations and Maintenance Benchmarking Industry Survey Results.
Means, R.S. 1995. Means Buildings Construction Cost Data, 53rd Annual Edition.
Northern Ecological Services. 1996. Annual Report, Bradley River Salmon Study Program, Alaska
Energy Authority.
LOCHER INTERESTS, LTD. PAGE 5.1 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
Polarconsult Alaska. 1993. Hydropower Study, North Fork Pyramid Creek. Prepared for the City of
Unalaska.
Polarconsult Alaska, 1994. Icy Creek Power Recovery Study. Prepared for the City of Unalaska.
Polarconsult Alaska. 1995. Old Harbor Hydroelectric Feasibility Study, Final Report. Prepared for Alaska
Village Electric Corporation. Anchorage, AK.
Rickman, Ron. 1997. United States Geological Survey. Personal Communication.
U. S. Army Corps of Engineers. 1984. Unalaska, Alaska; Final Small Hydropower Interim Feasibility
= Report and Environmental Impact statement. Alaska District. Anchorage, AK.
U. S. D. A., Soil Conservation Service. 1979. Exploratory Soil Survey of Alaska.
U. S. Fish and Wildlife Service. 1987. Kodiak National Wildlife Refuge Final Comprehensive
Conservation Plan, Wilderness Review and Environmental Impact Study. Anchorage, AK.
U. S. Fish and Wildlife Service, 1988. Alaska Maritime National Wildlife Refuge Draft Comprehensive
Conservation Plan, Wilderness Review and Environmental Impact Statement. Vol I. Anchorage, AK,
Voxland, Orville. 1995. Letter Report to Ms. Connie Lausten, Alternative Energy Development. (June 30,
1995). Re: Hydropower Development of Barling Creek; Old Harbor, Alaska.
LOCHER INTERESTS, LTD. PAGE 5.2 JANUARY 09, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE 11
I
3
l 6. EXHIBITS
EXHIBITS A: OLD HARBOR
J Al - Drainage Basin
A2 - Alternative Developments
A3 - Selected Project Layout
A4 - Land Ownership
A5 - Fisheries Resources
EXHIBITS B: UNALASKA
B1 - Drainage Basin
B2 - Icy Creek/Pyramid Creek Features
B3 - Alternative Developments
B4 - Selected project Layout
B5 - Land Ownership
B6 - Fisheries Resources
LOCHER INTERESTS, LTD. PAGE 6.1 JANUARY 09, 1998
J
LOCHER INTERESTS, LTD. EXHIBIT Al
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY OLD HARBOR
PHASE 11 DRAINAGE BASINS
Stream Gages
Streams
mmw� Basin Boundary
East Fork
OUpper
Barling Creek
(1.73 sq mi)
East Fork
Diversion to Gage
(0.38 sq mi)
�j
North Fork
�1
Barling Creek
(2.42 sq mi)
®Lower
Barling Ck
(3.22 sq mi)
®Lagoon
Creek
(2.71 sq mi)
4 ° 7d1 _\ ,`•—``/I 1111��1! YrX/F%/%i >'�
0
F
Z
Jr .
OR!J,
` 2 7
\ s
0.
/l `rsoo�/.1�
z J 500
CH
P
00 --- —:. - Mid
'644 Hill
/ S �
't. P• VABM
�J � / 20
/({
L ✓ 0
x
Lf/1/115sp�gn6
28
J
o t. 00 rtn
ZO/ _-
��
00 t`1,I t�: `�1'I 9 sr /i :. r'� ✓"!�
.....- ----------- KEY:
Streams
1 - 7 = ites Sampled by
AVEC in 1996
Extent of
Anadromous
Habitat
CO = Coho Salmon
.,:. CH = Chum
LOCHER INTERESTS, LTD. EXHIBIT A5 P = Pink Salmon
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY OLD HARBOR DV = Dolly Varden
PHASE II FISHERIES RESOURCES
\T/
ram,}
4�
11 i 11 ,l\ ji 1
1
r �Si f
r' -1�//dam f11
0
ul•
0
LOCHER INTERESTS, LTD. EXHIBIT A3
RURAL HYDROELECTRIC ASSESSMENT A14D DEVELOPMENT STUDY OLD HARBOR
PHASE 11 SELECTED PROJECT LAYOUT
".\UIIIKA�IIIII`.� .14 ti\l\�1K
2
ti N R4`��
,> �__y )� Q`.•a��, \ lI ` `' �'�� o 12 -r`,, 11 �.J 8
J', %l,. 20 (,•`X`li� f� _ _ / _ 5/00 1� ! '� .. • U ,e\ 690 .846
'�P,Iao -
f "' l
\/'1(16
j1 �V� 3 1 i�,L i'i.l_ U 1 - 6 OJ O\ I18
a
i
Midi a Bay
C1116 i\ 1 \ l 1� Lv / B1l/6
r/o'J / ' I - 1 ''r ) \)�) +,`\�• 1 \ o �� n V140 Tpi •• 0 aeP 1
20 /l/2
'f 't'1��,• I,�T ./i�/'i/ l\ f O�� - or �T/ii'.YIda
U0'OId H�Dyr.��/�
l 810
i 1. • ri
Chet �'•1. .1:
i
',I'•Seeplane) 91
U me 28Or
L
tQ
i rlh (S
1 /665
/
q �� �3a; `I;� Ali (� �� f, • `000
LOCHER INTERESTS, LTD.
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE 11
EXHIBIT A2
OLD HARBOR
ALTERNATIVE DEVELOPMENTS
KEY:
r Diversion
Penstock
• Power House
Water Course
1 = Upper Big Creek
2 = Big Creek Tributary
3 = East Fork Barling Creek
4 = Midway Creek
5 = Ohiouzuk Creek
V,
Al `
qH n
+
0 1 A VA1\ VvV 1
Devilfish
Point
C
fF
f
_
/
I
e@
2
B
L\1Ut�ia
�
iT�F&
ILI
0
2
e
C/]
<I 5 0
n i�1
i, KEY:
' Diversion
-Access-Read--
a er Treatment
• Plant
p( Creeks
1 = Icy Lake
2 = Icy Creek
3 = E. Fork Pyramid Creek
4 = Icy Creek Reservoir
5 = Pyramid Creek
LOCHER INTERESTS, LTD. EXHIBIT B2
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY UNALASKA
PHASE II ICY CREEKIPYRAMID CREEK FEATURES
\ 1
t
Hog 33 ON,
44
bit
��. T wvlv'•vvvv\v A,
'Point ,, �\�, _i ,l'• //
,old I n = , \ ...,�t 1d� _E\.' � 1i1H(�.`�ac 0
y,
�
I
Neck 2
Sou t�i )ro
Amaknek J7osk5
;'.
t3aJtey
Lodge
1'
Ober 2
__" •r'
Tanks
Lost 2
'
Bluff 2
o
r
p
3
LOCHER INTERESTS, LTD.
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE 11
p�W)
W
EXHIBIT B3
UNALASKA
ALTERNATIVE DEVELOPMENTS
0
0
UNALASKA
ALTERNATIVES
• Powerhouse
Penstock
1, 2 = Diversion Sites
3 = Icy Creek Reservoir
(Existing)
4 =1cy Lake Diversion
(Existing)
C
U
119.0
°
�Jle.e -1• elo.>�
Rule ell
/ny
ma.o
1r,0
I1
7
a¢1.e.a
T
eo*.a
/J/ lens.°
Ee6.6 P.05 4 `\
enae +
1 'li/e.e
nJn.J
-I-
ES.—SPP.P
eve./ `•�'t. /
aro•mA 910 nuln
F ,,
ell.,
eva.v •PEl
-I�
nne./1 L 33p
-1peo.1
eea.o�
1 eJ>.e
/ 3Go eee.e
• Jel.o -I-
S6Q eel., •
ale.e ,
1 _1pe/.l
Qalo./
-1Ree.l anl.eE i
�E•wPE., �Uy
V
1
1:ne.e.
EXHIBIT B4
UNALASKA
SELECTED PROJECT LAYOUT
ele.n
eeJ�
''pVVpry�0 Eeve
/le6.0
� ea,
, -I-
h \ eei.e j
E04.e
i =i
mo.e a1e.1
e.aO
eee.>
eil
eu
eoe.> �
-Joe.l 'I Doe.e i
enn.e
6e
1
-1=
n 42.0
KEY:
1 = Access Road
2 = Power House
3 = Lower Pyramid Creek
4 = New Penstock
5 = Existing Water Tank
6 = Existing Chlorination
Building
7 = Existing Water
Supply Pipeline
WE
LOCHER INTERESTS, LTD.
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE It
l �-
L—N
t
Ru1n�
Pu1P�.
-Fe1a \
In1 '119
fe7D III's
300
.Ind I
40.2
-I.x
i \
LOCHER INTERESTS, LTD.
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
jraee.e
•I sees
01a.0//
e40.1
+ale.a
� G
30
2;J.—LOP.e
Feoe.1 �+`♦ �-
IAw v✓ "
Co � 310 Auln�
1
e0e.0 J�•r0 eH.1F
-I' •1at4
•1-
aeelaea.a
-I-
a1e.11 3
30 i 110.1
aae.o f
_I eaT.e 1
�i 340�
960 'eels 11•
1 +111.1
Qb10.e
eoe.e F
aaiA
•� ene.e••
EXHIBIT B5
UNALASKA
LAND OWNERSHIP
61,
74.1 . ♦: •rye°•
C9
Lake
1a.eO
eee.r
y. 31
100.,
+a01.I .
_I a01.e
ene.e
' I
PYRAMID CREEK
Penstock
• Power
House
® Access Road
® Lot 1
Lot 2
Boundaries as shown are
approximate.
laJ/anV qH
L�Y
000., SlllA;►��\�� Cw/��i�r\l�\y�`\�\Y \\���\\�\�\�(,r
�. �t
Devilfish
Point
i
�. l Ja h jj��S14rf1�1{A�_/:SFG `Air ;`\,
I 5 : ol�i.l ' ' • v.,. ' Vn1Jltl'NTt W.�11� 11 ` \
0
0
KEY:
Streams
�Anadromous
Habitat for
Coho Salmon
and Pink Salmon
LOCHER INTERESTS, LTD. EXHIBIT B6
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY UNALASKA
PHASE II FISHERIES RESOURCES
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
7. PHOTOGRAPHS
7.1 OLD HARBOR
7.1.1 View from proposed powerhouse location looking upstream
along penstock alignment. East Fork Barling Creek in upper right
corner, Lagoon Creek across picture to lower left corner.
7.1.2 East Fork Barling Creek watershed. Stream gage located at
lone tree in foreground; proposed intake approximately 300 ft.
upstream of gage.
LOCHER INTERESTS, LTD. PAGE 7.1 JANUARY 9, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
M
LOCHER INTERESTS, LTD. PAGE 7.2 JANUARY 9, 1998
.rPr�r.r
t 1
e
c,+ � .. I +nt •¢Lys � t yt -� ��'3 `C -r.
. •\4 +q Y \4 M
,
�.
•'j+� Ili � ..:.. u,-.- ' .. � ..
j
jl 1
I i( rl J �(�� i u I•IIA 1 I�" I Y.
I it
v Kvy ' \ I�•��
AT
� II`� v I �Iv�� n I tt, 7•
'f t•�ti �P r ^'•
y I
4 ��� _FOP �I i � •`� ��F �' S r '. p S� %li
it � �� �X I ♦ i I � \ /- - .
e i ;m : • r9 �s� � /��th i � � ..
rm �
_ + f1� .\,�`,�s-a as+'.1dY*WS��',�.;J•4^MY.G.�y b -'•-
Ks�1kn
j ¢ , �" '' Air y * �`a•�. . _
y Y '$ y •ua' l �.
�s f
pax `�,� r rrpz�.
ION,
i '3r y�fy... t�' s � �'ss '�A1w, 4'.�1 \ L . ��• r
•1•' �.Jt.. r r' r 'iw'L �"!f f� (�. — F Fri.
}', a� ..� ''aleL�, m_i ' �Y +
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
7.1.11 Looking down proposed penstock alignment toward
proposed powerhouse location near green tree at center of picture.
Existing ATV trail along left bank of Lagoon Creek; proposed road
on right bank.
7.1.12 Proposed powerhouse location near tree on right bank of
Lagoon Creek; proposed load and transmission line along right
bank toward town at top of picture.
LOCHER INTERESTS, LTD. PAGE 7.7
JANUARY 9, 1998
-•"' �-.c'� '� E�J>. �j�.:.
I ���. n'^r-.o"� '+tee:
ItLi
.1V
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
7.1.17 Existing fuel farm and containment.
7.1.18 Abandoned freezer/chiller unit.
LOCHER INTERESTS, LTD. PAGE 7.10
JANUARY 9, 1998
.�-�re+m•F. ^�"�.'3`.�JAF^_,:-.ar ice^ - _
lux
l Y
if
,J
diyy("-�(.�'��i:
�L
r .�
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
7.2.5 Upper basin, Icy Creek.
7.2.6 Icy Creek upper falls.
LOCHER INTERESTS, LTD. PAGE 7.13 JANUARY 9, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
LOCHER INTERESTS, LTD. PAGE 7.14 JANUARY 9, 1998
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
7.2.8 Water supply reservoir.
7.2.9 Water supply diversion.
LOCHER INTERESTS, LTD. PAGE 7.15 JANUARY 9, 1998
Yr'F
fir- .,� ^—` •ti.� F.4 � T:";�_ � m•.—« :M"�^°r - , -
t
IWMB
AL'-3SO
N
� ''�!? _!'_�r '♦ I ! r ,+t""' � a zq '~fit ..
t
.-.��- �� nt-n.�o"T� „Ri�A'?�,• � ,toy �
i .' 1 n e!•?Y.r Fes H A a s ).
L ,
ll
/ J
1
✓i� j�iGk l�F,
Am
y
I
:
I p
`• t \ ,� , ?•' yam, f.. y "�n'� �'9� * Y�`�r f �j ���( ��
s ;5 i n �V <WJ t'/u / I I a•.I p f r �
/:1'`'1/ r �. / �� `t T �"• h ��)�ry;41 %l�j,��' rP ,s3i7) o.. r� �t J/y
7.2.14 East Fork Pyramid Creek. (Icy Creek drainage in upper righ
photo
t
2 _
4 f Y 1 _
mppw_ :777
A
ry �
RAW
1
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
7.2.20 Beginning of canyon reach and lower falls.
7.2.21 Canyon reach below water tank.
LOCHER INTERESTS, LTD. PAGE 7.21 JANUARY 9, 1998
APPENDIX A: ENERGY MODEL OUTPUT
Old Harbor
I
I
F
Imu
Project Data
PROJECT NAME:
Alaska Rural Hydroelectric Project
PROJECT NUMBER:
7204.H
CLIENT:
Locher Interests,
Ud.
Site Location:
Old Harbor
Pelton - Generated Efficiency
Data:
Penstock:
upper
lower
Input:
Material:
HDPE
Steel
Nominal Output, P (kW): 500
Penstock Diameter, ID (in) =
16
18
Nominal Efficiency, e:
0.88
Penstock Area, A M-2) =
1.40
1.40
Penstock Length, L (it)-
Penstock Manning's"n"=
3293
0.01
6966
0.012
Manning's "n" Method
Assumed:
Minor Losses:
H_losso (it):
210.2 Qnitiai assumption)
Loss Coefficients
-.
Coeff..k No. _•k
Initial Output:
H_neto(it)=
539.8(HWEL-TWEL-H_I
Entrance
90-deg band
1
0
0.5 0.5
0.13 0
Qo (cis) =
12.4 (=11.81-P / (H_net-e)
45deg bend
10
0.0975 0.976
Check:
H_lossi (it) =
210.2
22.5-deg bend
20
0.065 1.3
H_netr(it)=
639.8(HWEL-TWEL-HI
m=
ksu2.775
Q1(cfs)=
12A (=11.81-P1(HYe)
ne
Head Water Elevaton, HWEL (it) =
830
Nominal Rated Discharge, Q,eu6 (cfs) = 1 ;
Tail Water Elevation, TWEL (it) =
80
Net Head, H nK (it) _
$35Ii:6
Generator Efficiency =
93%
Minimum Discharge, Qm0 (cfs) =
1.3
Transformer Efficiency=
98%
Maximum Discharge, Qm.x (cfs) =
12.4
Required Instream Flow, Q_insU (cfs) =
0
(Instresm flow requirments, otherflow demands, etc)
Peiton ")^Turbine
Performance Curve
90%
w%
60%
75%
L
W
70%
0%
60%
0.00 2.00 4.00 6.00 4'00 ion 12.00
ohwy., o hnl
0wov,ns+au7eir u. �
rm,a
Q avail
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.H
CLIENT: Locher Interests, Ltd.
Site Location: Old Harbor
Available Flow
flow available for power generation
Q_avail = Q_gross - Q_byp
1
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Year
13.09
97.45
4.08
3.49
16.68
25.67
40.30
17.65
29.61
58.62
30.97
7.85
2
21.49
56.81
3.60
3.45
18.00
24.81
39.80
17AO
19.85
121.73
20.63
6.67
3
53.43
24.18
4.09
3.53
14.94
23.48
42.05
20.48
15.34
52.99
18.71
6.17
-j
4
74.62
16.03
8.68
3.83
13.83
25.77
36.02
33.45
20.04
36.74
14.02
5.49
5
34.51
31.60
25.29
4.68
15.28
29.76
3737
24.76
43.80
34.2
11.65
6.70
iJ
6
20.05
18.69
9.56
5.77
35.83
34.40
34.36
20.78
83.15
29.7
10.48
5.97
7
13.45
14.08
8.74
5.90
54.84
37.89
33.31
17.60
48.82
75.4
10.19
5.39
8
10.29
10.89
4.78
7.99
41.28
44.15
30.32
16.33
32.53
37.3
10.11
5.03
9
7.74
8.35
4.85
9.50
52.74
39.39
34.49
16.71
25.59
93.9
18.71
4.25
10
6.07
7.79
9.66
5.99
82.42
49.08
47.99
1520
26.07
43.4
17.98
4.35
11
5.57
6.98
6.44
4.93
56.00
70.72
80.12
13.79
25.62
302
17.01
4.03
12
5.12
6.94
4.41
4.33
51.49
74.82
80.52
13.89
24.63
232
14.68
7.56
13
4.77
8A0
5.29
4.13
51.97
60.41
57.97
12.43
18.91
21.10
13A5
6.18
14
4.52
6.29
7.85
4.06
39.49
46.93
42.43
15.14
1751
17.71
11.39
5.35
15
4.04
4.20
7.93
5.70
31.92
42.41
4332
13.49
15.88
15.7
10.01
4.81
16
5.05
3.57
5.73
1224
28.83
40.72
41.67
10.63
2035
19.7
8.26
4.84
17
4.94
3AO
8.63
12.64
25.44
40.10
70.68
9.76
9826
18.5
10.91
5.09
18
4.18
3.29
11.24
9.43
22.67
39.15
63.77
21.14
113.54
17.4
10.71
6.98
19
4.35
2.87
8.24
9.30
35.01
34.47
40.36
79.83
85.85
31.55
9.25
6.67
20
3.89
2.77
12.85
12.35
9138
32.99
3227
25.15
193.44
27.85
8.31
8.20
21
3.78
2.45
2.54
14.27
109.87
31.01
118.71
18.02
212.82
26.60
7.76
7.40
22
23
3.87
6.08
2.40
2.42
2.59
2.50
14.23
31.66
67.04.
67.82
29.87
34.25
85.55
149.35
13.68
11.30
70.32
40.36
41.45
25.52
14.51
7.36
24
7.59
2.40
2.27
38AO
54.71
30.64
36.74
10.27
57.63
19.95
10.83
10.98
10.64
1024
25
6.11
8.49
2.25
21.81
44.92
27.39
28.87
38.17
33.62
15.86
8.88
11.44
26
5.74
322
226
17.51
41.32
26.74
25.84
24.70
24.02
12.44
7.99
22.15
27
SA1
3.15
227
17.85
35.08
34.97
23.05
1925
18.48
9.79
7.15
35.31
28
7.57
4.54
2.65
19.49
34.53
37.49
20.78
15.18
25.74
9.43
6.03
28.68
29
29.96
-
2.71
17.14
31.86
35.15
19.81
25.51
20.20
11.05
5.86
41.55
30
57.38
-
3.30
20.01
28.75
34.52
17.81
38.18
29.91
41.20
9.20
24.20
31
60.22
-
4.41
-
27.72
-
17.41
32.79
-
55.00
-
15.92
TOTAL
494.88
361.33
191.69
345.61
1324.68
1139.13
1473.16
662.69
1491.88
1075.19
366.61
332.48
9259.34
MEAN
MAX
15.96
12.90
6.18
11.52
42.73
37.97
47.52
21.38
49.73
34.68
12.22
10.73
25.37
MIN
74.62
97AS
25.29
38.40
109.87
74.82
149.35
79.83
212.82
121.73
30.97
41.55
212.82
3.78
2.40
2.25
3.45
13.83
23.48
17.41
9.76
15.34
9.43
5.86
4.03
2.25
OHPOWIALS 12rbS7 9:07 AM HA 7304 H
Output 1
C
1
2
3
4
6
6
9
9
10
11
12
13
14
15
16
17
19
19
20
21
M
23
u
26
29
2]
23
29
30
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.11
CLIENT: Locher Interests, Ltd.
Site Location: Old Harbor
Nominal Output P (k14): SM.0
Nominal Rated Discharge, G.er (ors) = 12.4
Net Head, N„e,(n)= 539.E
Energy Output,
Jan
10938
Fab
lame
Mar
4825
Apr
May
Jun
Jul
Aug
Sop
pot
Nov
Dec Annual
IM36
lame
4265
4143
Q98
1006
10936
IM36
ions
INN
INN
109M
10936
8566
10936
lame
4934
4186
10936
INN
10936
INN
10936
10936
IM36
10936
lame
7499
INN
INN
9225
4535
10936
10935
10936
INN
40936
109M
INN
10936.4
10936.4
INN
M93
10936
INN
INN
INN
5502
1a936
INN
10936
10938
10936
10936.4
INN
107V
632D
7530
10935
10935
10936
9816
6591
10936
INN
10938
109W
10936
1WNA
10314
6790
10224
10504
9267
5610
6721
10936
lame
lame
10936
10936
10936.4
10174
U13
8472
Was
56]3
8685
9781
10936
10936
lame
INN
10936
INN
10936.4
10133
saw
Sam
W18
9880
6811
10936
1o836
INN
INN
10836
INN
10936
10936A
INN
6D14
Mae
77a0
7262
5758
10936
10936
lows
10936
INN
109H
10936.4
INN
5140
Soo
77S0
5207
5119
ID938
1006
1a936
lame
low
INN
IM36
IM36
IW36
4765
5a96
870
6116
48"
109H
10936
10936
INN
10936
10936.4
10936
10936
S315
WIN
5334
4770
7118
am
4800
10936
10936
10936
10936
10936
10936.4
10689
6175
5880
4958
4231
801
6559
027
10936
10936
lame
INN
INN
10936.4
1D081
W37
5774
4036
9190
INN
10936
10936
10936
INN
10394
IW36
10936.4
89M
566r
49M
3908
10640
9737
lama;
10936
10936
10936
10936
am
10936
loam
10514
S27
Spas
34M
Sam
9655
1a936
10936
IM36
10936
10936
109M
109M
10430
7790
4608
3293
IM36
10924
lo936
10936
1=6
INN
lame
10936
IM36
10936
1035
96/9
7498
4477
2901
=8
10936
10936
109M
INN
IM36
lame
lows
M38
U94
Bate
8166
4582
6897
2829
2852
was
loan
lame
INN
IM36
INN
1006
INN
10936
9131
K43
2837
2961
2672
109M
1093E
10936
IM36
10936
10936
10661
10936
10936
10482
10397
6936
7319
26M
10935
1a936
loan
10936
10936
10936
10219
109M
10935
10543
10203
6569
3830
209
1005
INN
lame
10938
10936
10936
INN
10936
930
10708
6233
3741
2670
10936
low
IM36
10936
tow
INN
10936
Saw
10936
8323
5350
3141
INN
10936
10936
INN
'10936
IM36
9955
7939
10936
109W
3222
10938
1083E
10936
INN
IM36
10936
10936
9734
10570
M53
INN
10936
10936
-
-
3918
awr
10936
_
10936
.,,,..�
10936
low
.____
10936
lows
10936
U84
9584
INN
10936
MAX
MIN
10,836
10,938
10 .935
10,936
lo,936
10,936
10,936
10.me
10.936
10,936
MFAN(My)
4417
325
am
2638
4098
10936
10936
10936
9939
10936
9734
10,936
6684
10,Ia."10,936
4785
638
MAX (I[V/f
456
285
456
257
4%
347
456
I56
.1
456
452
441
452
401
332
391
MIN W
187
lie
11n
171
456
Bee
456
—
456
.._
456
...
456
.__
46S
466
456
456
100.0% Percent Daily Generator Availability,
12p00-.—.... Mean
0 ito00 E1.--4-7-
0 €
Momh
DNGOWIXlS1Y1/d]8:0]gN
INBU
)I91H
I
APPENDIX A: ENERGY MODEL OUTPUT
2. Unalaska
Wu
Proiect Data
1 PROJECT NAME: Alaska Rum] Hydroelectric Project
PROJECT NUMBER: 7204.1-1
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska-Alternative#1
1
Energy recovery plant at treatment building Francis Unit- Generated Efficiency Date -
Penstock:
Input.
Material:
DI
Nominal Output, P (kW):
Penstock Diameter, ID (in) =
24
Nominal Efficiency, e: 0.88
Penstock Area, A (iM2) =
3.14
Penstock Length L (it)-
6000
Manning's "n" Method
Penstock Manning's "n" =
0.012
l
Assumed:
11
H_lossp (ft): 1.36 Initial assumption)
Minor Losses:
Initial Output:
Loss Coefficients
No.
Coen..
No.
H neto(it)= 186.45 (HWEL - TWEL -H_loss)
Entrance
1
0.5
0.5
Qo (cfs) = 3.60 (=11.81 •P I (H net-e))
90-deg bend
0
0.13
0
Check:
45-deg bend
10
0.0975
0975
H loss, (M = 1.35
225-deg bend
20
0.065
1.3
H_net, (it) = 186.45 (HWEL - TWEL • H_ioss)
k sum=
2.775
QI (cfs) = 3.60 (=11.81•P I (H_net e))
Head Water Eievaton, HWEL (ft) =
517.8
Nominal Rated Discharge, Om (cfs) = 3:G
Tail Water Elevation, TWEL (ft) =
330
Net Head, HM , (ft) _ 'fS5
Generator Efficiency=
93%
Minimum Discharge, O� (cis) = 1.7
Transformer Efficiency=
98%
Maximum Discharge, Q� (cfs)= 4.6
7
Francis Turbine
Perronnance Curve
90%
88%
I 1 I 1 I I
--------I--------I *-------- ----- ----- -------
I 1 I I I I
86%
I________}______ -____y________f_
y
T 64%
__IZT_- -J _L _____
1I
U
I 1 I
y
W
w
�%
_______1______I________i______-_7________'________
I
78%
1 1 I I I I
_1-_______I____-___I____-___1-_______-__-____-_
76%
I I I I 1 1
1S0 2.00 2.50 3.00 3.50 4.00 4.50 5.00
Discharge, Q (crs)
C
vrxwn xis,van r».w
M.
O avail
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.1-1
CLIENT: Locher Interests, Ltd.
ISite Location: Unalaska - Alternative #1
Available Flow
- flow available for power generation
Q_avail = Q_gross = Q dem
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Year
1
2.45
5.52
5.50
2.85
2.59
1.92
1.56
2.68
4.56
3.55
3.07
3.43
2
224
6.14
5.78
3.99
3.36
1.88
1.58
2.61
4.14
3.77
2.46
2.74
3
2.44
8.03
5.09
2.87
2.48
3.34
2.29
2.56
4.51
4.57
2.55
2.32
4
2.49
6.37
5.14
3A9
2.73
3.10
2.56
2.61
4.66
4.14
2.13
3.18
5
2AO
5.83
4.93
3.50
2.42
2.00
2.61
2.61
4.81
325
2.22
1.97
6
2.41
7.07
5.16
3.21
2.33
4.64
2.22
2.33
4.69
4.04
2.30
1.90
7
2.08
6.42
424
3.01
2.68
2.17
2.14
2.29
4.69
2.68
2.63
2.97
8
223
5.78
3.99
3.45
2.56
2.93
2.20
2.34
4.89
2.54
3.22
2.58
9
226
6.62
4.16
3.37
2.36
2.74
1.87
123
5.90
3.23
3.18
2.18
10
2.12
5.84
4.19
3A5
2.50
2.41
1.79
2.79
5.42
3.23
3.71
2.23
11
2.12
5.25
4.51
3.21
2.97
2.55
1.81
2.37
5.58
2.87
3.31
1.75
12
1.94
5.51
3.93
2.91
2.75
2A1
1.80
2.54
5.09
2.30
2.73
1.10
13
2.12
5.54
3.82
2.84
2.91
2.67
1.78
2.59
5.52
2.77
2.60
2.25
14
2.44
6.23
3.43
2.64
2.94
2.73
2.04
2.81
5.44
2.84
2.40
2.09
15
2.69
6.02
3.02
2.82
2.36
2.60
1.95
2.71
5.37
3.56
2.14
2.34
16
2.02
5.75
2.98
2.80
2.60
1.93
1.81
3.15
5.20
3.58
2.33
2.46
17
2.36
4.80
3.78
2.91
2.41
1.75
1.90
3.89
5.31
3.61
2.74
226
18
2.92
5.11
4.09
2.77
2.25
2.04
2.20
3.81
5.48
2.71
2.73
2.08
19
2.99
6.68
4.49
2.71
1.88
1.75
2.46
3.96
420
3.48
2.33
2.39
`
20
3.20
7.28
3.95
2.73
2.22
1A4
2.40
3.94
5.13
2.75
1.95
2.39
21
3.91
7.87
4A5
2.60
2.18
1.68
2AS
3.59
5.82
2.27
2.12
2.31
22
3.92
7.31
3.86
2.92
2.27
1.36
2.29
3.83
5.95
1.89
2.07
2.14
23
4.97
7.43
4.36
2.97
2.02
1.47
2.35
4.17
6.04
1.83
3.11
2.53
24
5.40
7.20
3.82
3.13
2.48
128
2.64
4.09
6.19
1.86
2.51
2.24
26
5.16
6.84
3.83
2.83
2.32
1.50
1.67
3.97
5.61
1.81
3.30
1.93
26
5.20
6.68
3.79
3.36
2.17
1.07
1.73
4.19
5.19
220
2.72
2.03
27
6.04
6.17
429
3.03
2.13
121
2.83
3.93
5.17
2.25
2.86
2.09
28
5.46
5.73
4.36
2.72
2.01
1.08
2.55
3.93
5.00
2.42
3.36
2.22
29
5.09
-
3.73
2.84
1.82
1.05
2.72
3.95
4.83
2.07
2.84
2.05
30
5.35
4.62
2.73
1.91
1.10
2.84
3.79
4.10
2.53
3.22
2.07
31
5.35
-
4.21
1.86
2.94
413
219
2.05
TOTAL
103.77
176.83
131.52
90.67
74.48
61.77
68.01
99.39
154.48
89.10
80.83
70.27
1201.12
MEAN
MAX
3.35
6.04
6.32
8.03
4.24
5.78
3.02
3.99
2.40
3.36
2.06
4.64
2.19
2.94
3.21
4.19
5.15
6.19
2.87
4.57
2.69
3.71
227
3.43
329
8.03
MIN
1.94
4.80
2.98
2.60
1.82
1.05
1.56
1.23
4.10
1.81
1.95
1.10
1.05
P POWIAL512rM78:36 AM HARZA 7204.H
PROJECT NAME: Alaska Rural Hydroelectric Project
ROJECT NUMBER: 7204.H
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska -Alternative #1
Nominal Outpu[ P (kvs): 50
Nominal Rated Discharge, Q..4 (cfs) = 3.6
Net Head, Ha., (R) = 186
Enerav Outuut:
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Doc Annual
1 705
1305
1305
848
757
625
0
788
1312
loan
922
1041
2 632
1299
1302
1192
1019
We
0
70
1226
1140
707
810
3 703
1279
13W
853
714
1011
649
743
1306
1312
742
658
4 719
1297
1308
1058
805
931
7"
761
1311
1227
594
959
5 07
1302
13M
1065
695
651
762
765
1310
984
624
541
a 690
1290
1307
971
663
1311
us
663
1311
12M
651
518
7 577
1297
1251
903
789
607
699
649
1311
786
768
ass
8 829
13U
1192
1048
7,t5
873
617
S67
1309
737
972
751
9 640
1295
1232
1021
672
809
508
0
1301
975
959
612
10 691
13D3
1239
1008
721
690
483
827
1305
975
1124
630
11 592
1307
1306
968
888
741
487
676
1304
853
1002
469
12 SW
1305
1179
an
all
690
484
738
1308
652
804
0
13 591
1304
1152
843
us
782
477
]54
13D5
Big
759
636
14 701
1298
1040
774
878
806
50
832
1365
843
687
581
15 732
1300
905
837
672
758
534
797
1306
1083
597
60
16 556
1303
892
828
759
528
486
949
1307
liar
662
709
17 672
1310
1143
869
691
469
518
1169
13DS
1095
810
640
16 870
13M
1217
Ws
636
565
618
1149
1305
799
NO
578
19 89e
1294
1303
70
512
488
708
1187
1241
1056
663
686
20 me
1288
1182
806
626
0
689
1181
1308
813
S35
684
21 1174
1281
1295
759
611
0
710
1090
1302
644
591
656
22 1177
1288
1163
870
642
0
650
1154
1301
513
573
597
Its 1309
12M
1275
888
556
0
672
1234
1300
40
936
732
L 1305
12M
1152
943
716
0
774
1217
1299
505
727
633
25 1307
i292
1164
839
661
0
0
1189
1304
488
09
527
28 1307
1294
1146
1018
609
0
462
1239
1307
619
802
561
27 1300
1299
1261
908
595
0
"1
1178
1307
637
"1
582
20 1305
1303
1277
802
554
0
740
1177
1309
am
1018
824
29 1308
1130
844
492
0
801
1183
1310
573
843
567
30 13M
1311
804
520
0
843
1144
1219
733
972
573
aui tx.r' 1,309 "to 1.311 1.192 1,019 1,311 843 1.239 1.312 IA12 1.124 1,041 1.312
MIN (kW-0r1 530 1 Y79 892 ]59 d92 D D 0 1219 488 535 0 0
MEAN (kW) 37 54 50 38 Z9 18 24 39 52 35 32 26 36
MAX( W) 55 55 65 50 42 55 35 52 55 65 47 43 55
Percent Daiy Generator Avail birdy
1M4
rurm
1
)
I
t {
0A
i F
V
i
i
o-a
i
Maan Monihy Output
1,400
1,i00
1,W0
C
9
I
1
{t{
! 1
nr8a0w1 xis 111L37 ewe wu w�au 7zaH
Output 2
PROJECT NAME: Alaska Rural Hydroelectric Project
ROJECT NUMBER: 7204.1-1
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska - Alternative #1
330,000
310,000
Y 290,000
270,000
a
250,000
O
a 230,000
L
210,000
W
190,000
00 170,000
a
150,000
PYR P O W 1.XL5 12/2197 8:46 AM
Penstock Diameter, D (in)
24
Turbine
Size
HL
Qpwr
Eyr
(M)
(ft)
(cfs)
(kw-hr / yr)
10
0.1
0.7
95,514
20
0.2
1.4
189,126
30
0.5
2.1
263,906
40
0.9
2.9
301,213
45
1.1
3.2
312,213
50
1.4
3.6
319,128
52
1.5
3.7
320,086
55
1.6
4.0
318,883
60
2.0
4.3
313,295
70
2.7
5.1
278,505
80
3.5
5.8
233,689
100
5.7
7.4
176,629
150
14.0
11.6
63,451
200
30.31
17.01
2,062
Turbine Size vs. Annual Energy
-
--------------------- - - - - -'
--------r----------
----------_;--------'---WP_enstock ------;-----------
I 1 I I
1 -J _I -L
I
_J----------------- L _
1 I I
F
I I I
0 20 40 60 80 100
Turbine Size (M)
HARZA
7204.H
l�u
Proiect Data
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.H
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska - Altemative #2
Plant at Blow -off
Penstock:
Material:
DI
Penstock Diameter, ID (in) =
24
Penstock Area, A (f02) =
3.14
Penstock Length, L (ft)--
4700
Penstock Manning's "n" =
0.012
Minor Losses:
-•� Loss Coefficients
No
Coef . kk
No. - it
Entrance
1
0.5
0.5
T - branch flow
1
0.75
0.75
45-deg bend
10
0.0975
0.975
22.5-deg bend
20
0.065
1.3
k sum =
3.525
Head Water Elevaton, HWEL (ft) =
517.8
Tail Water Elevation, TWEL (ft) =
255
Generator Efficiency =
93 %
Transformer Efficiency =
98%
r
11
Francis Unit- Generated Efficient Data -
Input:
Nominal Output, P (kW):
Epp:
Nominal Efficiency, e:
0.88
Manning's "n" Method
Assumed:
H_losso (ft):
23.78 (Initial assumption)
Initial Output:
H_neto(ft)=
239.02 (HWEL-TWEL-H_loss)
Oo (cfs) -
16.84 (- 11.81"P / (H_net•e))
Cheek:
H lossl (it) =
23.7E
H netl(it)=
239.02 (HWEL-TWEL-H_loss)
at (cfs) =
16.84 (- 11.81'P / (H_nePe))
Nominal Rated Discharge, 0r (cfs) _
I x
Net Head, Ho,, (ft) =
23'
Minimum Discharge, Q, (cfs) =
7.9
Meldmum Discharge, Cm„ (cfs) =
21.2
Francis Turbine
Performance Curve
90%
I 1 I I I I
I I I 1 I 1
J _J
I 1 1 I
I 1 1 I
86%
I I
1 I I I I I
________I_________________1_________________________I________
I
at
I 1 1 I 1
Y 84%
r —1 y
e
I I 1 I I
W1
1 I 1 I I I
1 I
80%
1 I I I
1 ________- ______ I___________________________________1
I I I 1 1
I I 1 I I I
1 1 1 1 I
1
I 1 1 1 I 1
76%
7.50 9.50 11.50 13.51) 15.50 17.50 19.50 21.50
.Oischarge, Q(chi
IVNOWtA91LL9)e]!IL �
1101H
C avail
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.H
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska - Alternative #2
Available Flow
- flow available for power generatlon
Q_evall = Q_gross - Q_dem
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Year
1
16.03
0.00
17.39
1.07
9.04
27.33
27.69
26.57
0.00
25.70
19.08
1.46
2
13.15
0.00
23.47
0.16
7.08
27.37
27.67
21.33
0.00
14.03
17.37
1.66
3
19.94
0.00
23.41
2.68
7.03
25.91
26.96
18.72
0.00
9.83
14.18
4.38
4
2277
0.00
16.25
2.05
6.56
26.15
26.69
8.82
0.00
11.88
12.80
2.70
5
20.54
0.00
12.67
13.39
6.74
27.25
26.64
0.00
0.00
14.55
11.07
4.79
6
15.08
0.00
11.07
26.04
7.30
24.61
27.03
13.07
0.00
13.77
9.50
2.97
7
12.55
0.00
10.89
26.24
7.65
27.08
27.11
26.96
0.00
14.20
13.18
2.52
8
12.64
0.00
8.98
21.12
8.15
26.32
27.05
17.86
0.00
26.71
10.87
9.50
9
11.70
7.63
6.34
14.04
8,33
26.51
27.38
26.02
0.00
20.94
26.07
8.98
10
10.37
5.07
4.98
8.17
12.32
26.84
27.46
26.46
0.00
15.50
25.54
25.12
11
9.54
12.62
3.75
4.65
13.23
26.70
27.44
11.62
4.04
12.32
17.47
16.41
12
9.D4
10.30
160
4.68
13.95
26.84
26.27
1.71
2.32
12.89
17.94
11.61
13
8.29
6.11
1.54
3.67
12.98
26.58
22.86
16.64
0.00
10.89
21.20
7.57
14
7.83
230
0.00
4.91
13.06
26.52
23.22
0.00
0.80
9.41
21.35
6.15
15
11.84
1100
0.00
26.43
15.63
26.65
25.83
13.34
3.10
8.04
21.00
4.72
16
17.16
0.00
26.27
6.10
19.97
27.32
27.44
11.20
2.35
9.78
23.14
3.55
17
11.11
0.12
13.23
5.53
23.44
27.50
27.35
7.32
3.63
8.64
23.80
4.52
18
8.95
0.00
0.00
11.83
27.D0
27.21
25.28
5.49
3.31
6.89
18.84
3.89
19
7.85
22.57
0.00
7.76
27.37
27.50
26.79
7.55
2.64
8.12
1935
2.75
20
6.82
21.97
5.72
5.50
27.03
27.82
24.07
5.85
3.34
8.22
22.05
3.09
21
5.67
21.38
1.24
5.02
27.07
27.57
25.57
3.24
23.43
10.67
27.13
2.38
22
3.54
21.94
4.65
4.12
26.98
27.89
23.22
0.72
21.29
9.71
1&65
6.21
23
0.32
9.18
24.89
6.05
27.23
27.78
20.24
0.00
11.52
23.59
13.03
11.11
24
0.00
0.00
25.43
14.83
26.77
27.S7
18.20
0.00
6.29
15.02
13A6
2.16
25
0.00
10.23
25.42
25.44
26.93
27.75
18.72
0.00
7.07
10.44
16.34
1.35
26
0.00
5.34
25.46
17.67
27.08
28.18
18.18
0.00
5.86
9.40
18.25
2.51
27
0.00
11.29
24.96
13.25
27.12
28.04
17.45
0.00
2.63
14.62
13.42
10.22
28
0.00
14.09
3.58
12.20
27.24
28.17
22.12
0.00
1.64
20.57
18.41
23.37
29
0.00
6.92
14.23
27.43
28.20
11.55
0.00
10.31
27.18
24.66
6.76
30
0.00
-
0.30
14.51
27.34
28.15
16.70
0.00
25.15
20.46
20.87
4.59
31
0.00
0.00
-
27.39
21132
0.00
13.83
25.55
TOTAL
262.73
182.15
332.41
323.34
572.43
815.73
740.50
272.47
140.70
439.78
546.67
224.76
485167
MEAN
8.48
6.51
10.72
10.78
18.47
27.19
23.89
8.79
4.69
14.19
18.22
7.25
13.30
MAX
22.77
22.57
26.27
26.43
27.43
28.20
27.69
28.D2
25.15
27.18
27.13
25.55
29.20
MIN
0.00
0.00
DOD
0.16
6.56
24.61
11.55
D.D0
0.00
8.04
9.50
1.35
0.0D
PYRPOMYLS 1L 7&9a AM Hg67A 12aCN
Output 1
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.1-1
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska -Alternative #2
Nominal Output, P (kW): 300
Nominal Rated Discharge, Q,,,,a lots) = 10.0
Net Head, H,,,,, (it) = 239
Enerov putout
Jan
Feb
Mar
Apr
Me,
Jun
Jul
Aug
UP
Oct
Nov
Doc Annual
5107
0
6184
0
W15
6320
6320
6320
0
6320
logo
0
W62
0
63M
0
0
6320
020
7103
0
53M
6480
0
6974
0
6440
0
0
6320
6320
6756
0
3584
5446
0
W22
0
5938
D
0
6020
6320
3220
0
4448
Q26
0
7064
0
4723
5083
0
6320
6320
0
0
5539
41M
0
5787
0
4064
6320
0
6320
6320
6026
0
5191
3514
0
4828
0
4032
am
0
6320
6320
6320
0
5445
6054
0
48W
0
32"
6993
2941
6320
6320
6614
0
6320
4063
3508
4455
0
0
5337
3021
6320
am
6320
0
7004
6320
3298
3891
0
0
2934
4712
6320
SV0
6320
0
saw
6320
6617
$536
4654
0
0
W52
EM
63M
4418
0
4694
6428
6284
3330
3739
0
0
5345
6320
6508
0
D
4956
6590
6466
3010
0
0
0
4961
M20
7009
6286
0
4089
7115
0
0
0
0
0
499D
1=0
69M
0
0
3461
7128
0
4497
0
0
6320
6978
M20
6552
5111
0
M74
7152
0
6477
0
M20
0
%at
6320
6320
4207
0
3584
on
0
4201
0
5004
0
6839
632D
63M
0
0
34M
6739
0
Misr
0
0
4492
6320
02D
8597
0
0
3248
9759
0
0
6320
0
0
W20
6320
63M
0
0
2912
6893
0
0
632D
0
0
020
6320
6748
0
0
2968
7054
0
0
6320
0
0
$320
6320
6514
0
M20
4013
6320
0
0
632D
0
0
6320
020
6885
0
6636
3618
6008
0
0
3219
6320
0
M20
=a
7031
0
4202
6900
4967
4192
0
0
8320
560
6320
020
6646
0
0
5802
505i
0
0
3854
6320
8476
6320
M20
6850
D
0
3930
6131
0
0
0
6320
6470
6320
6320
6/35
0
0
U74
M50
0
0
4105
6320
5D55
632(1
020
6470
0
0
5636
5132
W28
0
5191
0
4649
6320
M20
7005
0
0
7064
6614
6877
0
0
5447
020
6320
4371
0
3771
63M
6595
0
0
0
6560
632D
632o
6281
0
fi320
7038
sell
0
MA ( 7,064 6.320 6,440 6,993 5.961 6.320 7,060 7,103 6,06 7,D64 7.152 1.877 7.162
MIA! 0 0 0 0 0 6320 4371 D 0 2874 3514 0 0
MFAN(kllp 113 74 113 115 192 255 270 99 37 W2 245 lit 150
MA1t(k1M) 294 263 268 291 290 263 294 296 276 294 298 287 298
Percent Daly Generator Availability
to0xzem
Ox
Month
e0x
70xox
e
�l�
f-
r
jj
1
a
i
20%
E
{
,ax
Mean Monthly Output
6,000
I f
o
.DOD
C1
0'
Month 3
PYPPOW$X151}/S9]0 ]B NA Hppy1
]]WH
Output 2
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.1-1
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska - Alternative #2
Penstock Diameter, D in
Turbine
24
Size
HL
Qp.,,,
Ey,
kW
(ft)
cfs
kw-hr/ r
70
1.08
3.69
523.363
100
2.22
5.15
706,851
200
9.4
10.59
1,144,267
300
23.78
16.84
1,313,272
350
35.91
20.7
1,293,499
380
46.66
23.59
1,247,672
390
51.34
24.75
1,212,919
400
57.03
26.09
1,184,407
410
64.57
22.76
1,123,625
415
69.72
28.85
1,059,244
420
77.76
30.46
984,508
Turbine Size vs. Annual Energy Output
1,400,000
I I I I
----------1---------- I-
--1II
1,200,000
1__________ ___ _________
�L3
II
1
000
1,1oo,00a
----------r--_____-- -------
____-I1
O 900,000
----------i------------------------------iI' ----------
24" Penstock
m` 800,000
----------*- -------------------
WQC
700,000___________________
___________II ----------- LII
_-________m
II1----------
600,000
----- - ----------------------
I
500,000
1
------------------------------i-----------r------- --
I I I I
400,000
0 100 200 300 400 500
Turbine Size (kW)
PYRPOW2-)US 122/978:38 AM HARZA 7204.H
I�.
Proiect Data
PROJECT NAME:
Alaska Rural Hydroelectric Project
PROJECT NUMBER:
7204.H
CLIENT:
Locher Interests, Ltd.
Site Locaflon:
Unalaska -Alternative *3
Icy Cr. / E Fork Pyramid Cr. confluence to plant at tidewater Francis Unit- Generated Efficiency Data -
Penstock:
Input:
Material:
Steel
Nominal Output, P (Wv):
$0a
Penstock Diameter, IO (n) =
30
Nominal Efficiency, e:
0.88
Penstock Area, A (fta2) =
4.91
Penstock Length, L (it)=
6150
Mannma's "n" Method
Penstock Manning's Y =
0.012
-
Assumed:
Minor Losses:
H_lossa (it):
30.53 (initial assumption)
Initial Output
Loss Coefficients
hto Coen, k No,_-k
H_neto(it)=
264.47 (HWEL - TWEL - H_loss)
Entrance
T - branch flow
1 0.5 0.5
0 0.75 0
Do (cis) =
30A5 (= 11.81-P / (FLnere))
45-deg bend
10 0.0975 0.975
Check:
H_lossr (it) =
30.53
22.5-deg bend
20 0.06.5 1.3
H_netr(it)=
204.47(HWEL-TWEL-H_1ow)
"urn= 2.775
OI (cis) =
30.45 (= 11.81'P / (H_nere))
Head Water Elevaton, HWEL (it) =
315
Nominal Rated Discharge, O„I,o (cfs) _=
Tail Water Elevation, TWEL (it) =
20
Net Head, Haw (ft) _NO
Generator Efficiency=
93%
Minimum Discharge, O,,,a1(cfs)=
14.3
Transformer Efficiency =
98%
Maximum Discharge, Ora.. (cfs) =
38A
Francis Turbine
Perfom nse Curve
90%
I I I I I 1
1 I 1
I I I I I
J________L_______ L_______1________I___ ____
c
1 1 I I I I
_______ -________I_
w
I I I I I
1 1 I I I
1 I I
I 1
I I I I I I
76%
BAD 1150 1850 2130 26S0 31.50 36.50 41.50
Gscharaa,p(cfsl
✓"M.N.V IfN)tlY.41
'�U 1dMN
O avml
I
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.1-1
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska -Alternative #3
Available Flow
- flow available for power generation
Q_avail = Qyross
1
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Year
2
23.78
0.95
26.99
3.14
12.20
99.46
91.34
42.29
2.28
40.38
28.33
3.53
3
19.60
0.96
51.48
2.23
9.88
110.44
71.63
30.51
2.15
21.50
25.69
3.79
4
29,32
0.93
35.36
15.51
9.51
85.49
66.28
29.34
2.04
15.87
21.20
7.18
5
33.37
2.18
25.22
14.87
9.03
95.33
64.64
16.40
2.94
16.60
19.06
5.16
6
30.16
1.36
20.D5
26.21
9.89
137.58
89.65
6.40
25.60
22.02
16.65
7.63
22.42
0.90
17.88
43.41
10.10
151.53
88.51
28.22
15.82
21.23
14.44
5.01
7
18.69
0.85
17.24
78.93
10.45
147.04
66.29
41.32
6.68
21.28
19.81
4.82
8
9
18.87
1.81
14.41
38.71
11.11
126.58
63.89
38.39
5.09
39.29
16.78
14.56
10
17.55
13.61
10.75
23.02
11.87
117.64
58.58
44.27
253
31.08
40.37
13.66
11
15.61
9.56
8.83
15.46
15.12
107.67
52.05
61.11
4.77
23.36
32.98
36.59
12
14.43
20.11
7.22
10.86
16.20
111.88
58.21
22.47
5.80
18.69
21.36
24.02
13
13.65
16.94
6.76
9.67
16.92
123.73
48.60
10.86
3.31
19.26
21.60
16.95
14
12.66
11.00
3.78
7.88
16.33
137.72
40.92
25.34
2.30
16.62
30.47
11.69
15
1214
5.87
1.18
1260
20.35
129.36
42.69
6.68
3.87
14.54
27.61
9,60
17.93
2.05
1.12
33.61
32.78
132.70
57.99
21.21
5.06
12.90
26.90
7.67
16
25.21
1.67
49.83
10.56
38.83
129.44
69.12
21.12
4.64
15.50
42.48
6.07
17
16.76
2.18
20.36
18,35
51.99
135.02
63.96
14.28
5.62
13.78
46.24
7.36
18
13.93
1.34
1.44
20.38
56.22
244.43
46.93
13.06
4.71
13.75
39.17
6.39
19
12.39
83.33
1.81
13.32
70.29
255.25
50.42
13.76
4.89
1299
64.83
4.91
20
11.02
199.76
9.77
10.21
75.37
218.06
44.76
11.83
15.18
1282
34.20
5.39
21
9.69
254.98
3.62
9.00
69.28
221.39
46.84
8.93
38.32
16.09
66.60
4.35
22
6.66
50.64
8.22
7.66
79.56
147.45
43.60
6.12
24.71
14.58
30.63
9.71
23
24
2.54
16.15
188.57
9.21
73.04
100.92
35.82
5.11
13.72
34.25
31.42
16.83
25
2.10
3.01
240.90
17.99
59.46
88.54
35.15
5.57
9.61
22.09
23.51
4.01
2.10
17.39
240.89
28.24
52.41
a6.59
36.21
4.64
9.56
15.57
24.65
2.73
26
2.04
10.39
221.16
20.30
58.59
76.15
34.16
5.06
8.39
14.26
24.88
4.42
27
2.04
18.62
51.10
15.72
62.01
64.88
35.30
4.85
5.08
21.70
20.24
15.38
28
29
1.94
22.40
6.91
14.53
59.48
72.58
42.85
4.16
14.36
30.21
27.54
34.10
30
1.84
-
11.39
16.57
55.68
80.45
27.53
3.93
41.80
123.10
36.19
10.45
31
1.62
-
1.34
17.31
77,95
108.96
30.79
3.56
85.88
30.10
30,97
7.38
TOTAL
1.07
-
1.04
-
73.67
35.43
4.14
20.55
37.13
MEAN
413.11
770.93
1306.S3
563.4
1225.59
3846.26
1638.16
554.93
376.70
747.95
906.81
348.48
12699.01
MAX
13,33
27.53
42.15
18.78
39.54
128.21
52.84
17.90
12.56
24.13
30.23
11.24
34.79
MIN
33.37
254.98
240.90
78.93
79.56
255.25
91.34
6111
85.88
123.10
66.6D
37.13
255.25
1.07
0.86
1.04
2.23
9.03
64.88
27.53
3.56
2.04
12.82
14.44
2.73
0.86
PYRPOV 'XIS 1=97439m
n94.x
-j PROJECT NAME: Alaska Rural Hydroelectric Project
31 PROJECT NUMBER: 7204.1-1
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska -Alternative #3
I
1
2
3
4
6
6
7
8
9
10
11
12
13
14
16
18
17
18
19
20
21
22
23
24
28
28
27
29
39
30
Nominal Output P (WV): No
Nominal Rated Discharge, 12, (cfs) = 30.4
Net Head, Haw (it) = 2U
Enerav Output:
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec Annual
10415
0
11824
0
0
14736
14M6
147M
0
14736
12353
0
8402
0
74736
0
0
74736
14736
13139
0
9333
112M
0
12727
0
14278
84t6
0
74736
14MS
12Y34
0
65M
9187
0
13871
0
11058
6115
0
147M
14736
6847
0
M13
87M
0
13029
0
8622
11499
0
74736
147M
0
11226
95N
065
0
am
0
7563
14736
0
74736
14736
12311
067
9201
5910
0
7965
0
7254
14736
0
14736
14736
14736
0
9=4
wu
0
8045
0
5890
19571
0
t4736
14736
14736
0
74736
7027
5969
7405
0
0
10067
0
74736
74736
14736
0
13304
147M
0
6464
0
0
6395
6230
147M
74736
74736
0
10223
137M
14494
69M
W51
0
0
6746
14736
14736
9806
0
7954
9264
10523
0
7104
0
0
7098
14738
14735
0
0
8233
9385
7109
0
0
0
0
all
74736
74736
11111
0
6951
13123
0
0
0
0
0
87M
74736
74736
0
0
Sea
12066
0
7589
0
a
13924
13742
14738
147M
9191
0
0
117M
0
11052
0
14736
0
14739
14736
14M
9147
0
6415
14736
0
7021
0
8771
7791
14736
14736
14736
0
0
0
14736
0
0
0
0
8781
14738
14738
14738
0
0
0
147M
0
0
141iX
0
0
74736
14736
14736
0
0
0
147M
0
0
14736
0
0
14736
14736
14736
0
8262
0
14 19
0
0
14M6
0
0
14738
14736
14738
0
14731
se56
W36
0
0
Una
0
0
14736
14M
14735
0
10930
S74
13171
0
0
6M
14736
0
14735
14736
14361
0
0
14061
13398
7051
0
0
14736
7616
14736
147M
14240
0
0
9627
10293
0
0
7327
14736
1231a
14730
14736
14d30
0
0
6448
10805
0
0
0
14736
8745
14738
74736
14042
0
0
0
10908
0
0
7920
14736
6520
14738
14736
14267
0
0
9433
8715
6358
0
9776
0
5952
14738
14736
14736
0
W71
IM42
120Q
14029
0
0
6926
14735
14736
1237
0
14738
14736
14427
0
0
0
72M
14736
14736
13218
0
14736
13009
13271
0
MAX 13.871 14,736 14,736 14.739 14.736 U,738 14,738 14,736 14,736 4,736 14.736 11,572 td,736
MIN 0 0 0 0 0 14 Me 12037 0 0 0 5910 0 0
MEAN (kW) 174 158 240 237 0 as 604 212 114 326 468 108 306
MAX(k.M 578 614 614 614 614 614 614 614 614 614 $14 607 814
Percent Daily Generator Availability
100%
s
a
{
LT
20%
10x
�...... 1...,
i
3
0%
Mea7n
18,000 Mean Monthly Output
€
14,000---"------- "'
--_-----.._-
0 � f
t €—.
I +
a '
IS
Month
GYR00`MXIS iN9] e:M PM 1{1yJ, RDtH
ON 2
I
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER:7204.H
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska - Alternative #3
3,000,000
2.500,000
2,000,000
1,500,000
1,000,000
500,000
Penstock Diameter. D in
Turbine
18
1 24
1 30
size
H,
0w
I E1,
AL
Oa
Fx
I
HL
Q�;
k)
ft
cfs)
kw-hrl r
ft
cis)
kw-hr/
ft
Ws)
kw-hr/ r
50
2.57
2.29
457,983
100
10.91
4.72
839,422
2.24
4.58
857.393
150
27.72
7.53
1.145,346
5.15
6.95
1,211,067
200
68.82
11.87
1,247,115
9.43
9.4
1.516,428
278
9.19
1.540.985
300
23.47
14.83
1,948,555
6.41
13.95
2,047,015
350
34.79
18.05
2,079,145
8.88
16.42
2.232,096
400
52.18
2211
2096,140
11.84
18.96
2.404,672
420
63.05
24.3
2,056,534
13.18
20
2,456,943
430
70.62
25.72
2,029,988
13.88
20.53
2,469,036
440
82.22
27.75
1.952,118
14.61
21.06
2.475,881
450
15.36
21.6
2,502,065
500
19.55
24.36
2,587,249
600
30.53
30.45
2,675.005
620
33.29
31.79
21653.547
650
37.92
33.93
2,625,427
700
47.42
37.94
2,551,817
750
60.88
42.99
2.451,805
800
1
1
1
93.5
53.28
2.086.753
Turbine Size vs. Annual Energy Output
T-
I I 1 1 I I I
1 1 1 1 I 1 I
1 1 1 I I I I
1 1 I 1 1_ ►T._ 1
I 1 I r I\----
/ 1 1 70" P4nstock 1 \
I I I .�" I I I 1
7__-____I_
24"Penstock I 1 1
1 1 I I 1 I 1
I I I I I I I
I I 1 I I 1 I
_L _I L _I _1 _I
1 I I I
f \ I
� 8" Penstocl�
1 i I I I I I
1 1 I I I I I
I I I I 1 I I
I I I I I I I
I 1 1 I I I I
100 200 300 400 500 600 700 800
Turbine Size (kW)
rrnrow.l.xts 1]RR7 eas u4 W16IA
n04.H
Project Data
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER:
7204.1-1
CLIENT:
Locher Interests,
Ltd.
Site Location:
Unalaska -Alternative
94
Treatment building to plant at tidewater
Penstock:
upper
lower
Material:
DI
Steel
Penstock Diameter, ID (In) =
24
24
Penstock Area, A(ft^2)=
3.14
3.14
Penstock Length, L(11
6000
2450
Penstock Manning's W' =
0.012
0.012
Minor Losses:
Loss Coefficients
No.
CoeB., it No. • k
Entrance
1
0.5 0.5
T - branch flow
1
0.75 0.75
45deg bend
10
0.0975 0.975
22.5deg bend
20
0.065 1.3
k_sum= 3.525
upper
lower
Head Water FJevaton, HWEL(it)=
517.8
270
Tail Water Elevation, TWEL (it) =
270
20
Generator Efficiency =
93%
Transformer Efficiency=
98%
Francis Unit- Generated Efficiency Data,
Input:
Nominal Output,? pq
Nominal Efficiency, e: 0.88
Manning's "n" Method
Assumed:
H_Ios% (ft): 46.67 (initial assumption)
Initial Output:
H_ne6(it)= 451.23(FIWEL-TWEL-H_loss)
Oo (cfs) = 17.86 (= 11.81 •P / (H ne&))
Check:
H_10ssl (R) = 48.67
H_ne%(ft)= 451.23 (HWEL-TWEL-H_loss)
Ci (cis) = 17.85 (=11.81-P / ()-net"e))
Nominal Rated Discharge,C, (cfs)
Net Head, H„�-.,jij
Minimum Discharge,O„e, (cfs) = e
Mammum Discharge,O,,,.(cfs)= 22
Franca Turbine
Performance Curve
90%
I I 1 1 I I I I
I 1 I I I 1 1 I
1
I 1 I I I I 1 1
I I I I 1 I 1
I 1 I I I 1 1
I 1 1 I I 1 I 1
I I I I I I
XBeX
1 I I I I 1 I I
I I I _____ I______I______I______ I ______
6
I I I I I I I I
I I 1 I I I I 1
1 I 1 I I I I I
I I 1 I 1 1 1 I
I 'I_ T T ______T______
I I 1 1 I I I 1
I I 1 I I I I I
I 1 1 1 1 I I
I I 1 I 1 1 I I
I I I I I I I I
7G%
I I 1 I I 1 I I
I I I 1 I
5.50 7.50 "a 11.50 13.50 1550 17.50 19.50 2"0 23.50
Dlsehar0e. p (eft)
vmwwlxislmme�lue w+w rawa
O avail
PROJECT NAME: Alaska Rural Hydroelectric Project
ROJECT NUMBER: 7204.H
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska - Alternative #4
Available Flow
flow available for power generation
Q_avail = IF Q_gross-Q clem < 0 THEN 0 ELSE QLgross-Q_clem
Jan
Fab
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nav
Dec
Year
-�
1
16.03
0.00
17.39
1.07
9.04
28.59
28S5
27.83
0.00
26.96
19.06
1.48
2
13.15
0.00
24.73
0.16
7.08
28.64
28.93
21.33
0.00
14.03
17.37
1.86
3
19.94
0.00
23.41
2.68
7.03
27.17
28.22
18.72
0.00
9.83
14.18
4.38
4
22.77
0.00
16.25
2.05
8.56
27.42
77.95
8.82
0.00
11.88
12.80
2.70
5
20.54
0.00
1257
13.39
8.74
28.51
27.90
0.00
0.00
14.55
11.07
4.79
6
15.08
0.00
11.07
27.30
7.30
25.87
28.29
13.07
0.00
13.77
9.50
297
7
1255
0.00
10.89
27.50
TS5
28.35
28.37
28.22
0.00
14.20
13.18
252
8
1264
0.00
8.98
21.12
8.16
2T58
28.31
17.86
0.00
26.03
10.87
9.50
9
11.70
7.63
6.34
14.04
8.33
27.77
28.64
28.79
0.00
20.94
27.33
8.98
10
10.37
5.07
4.98
8.17
1232
28.11
28.72
27.72
0.00
15.50
26.80
25.12
11
9.54
12.62
3.75
4.85
1323
27.96
28.70
I I S2
4.04
1232
17.47
16.41
12
9.04
10.30
3.60
4.88
13.95
28.11
26.27
1.71
232
12.89
17.94
11.81
13
8.29
6.11
1.54
3.97
1298
27.85
22.88
16.64
0.00
10.89
21.20
7.57
14
7.83
2.30
0.00
4.91
13.08
27.78
23.22
0.00
0.80
9.41
21.35
6.15
15
11.84
0.00
0.00
77.69
15.83
27.92
25.83
13.34
3.10
8.04
21.00
4.72
16
17.16
0.00
27.53
6.10
19.97
28.58
28.71
11.20
235
9.78
23.14
3.55
17
11.11
0.12
13.23
5.53
23.44
28.76
28.61
7.32
3.63
8.64
23.80
4.52
18
8.95
0.00
0.00
11.63
2526
28.47
25.28
5.49
3.31
8.89
18.84
3.89
19
7.85
23.83
0.00
7.76
28.63
28.76
28.05
7.55
2.64
8.12
19.35
275
20
6.82
23.23
5.72
5.50
21129
29.08
24.07
5.85
3.34
8.22
2205
3.09
21
5.67
2264
1.24
5.02
28.33
28.83
25.67
3.24
24.69
10.67
28.39
Z38
22
3.54
23.20
4.65
4.12
28.24
29.15
23.22
0.72
21.29
9.71
15.65
6.21
23
0.32
9.18
26.16
6.05
2849
29.04
2024
0.00
11.52
23.69
13.03
11.11
24
0.00
0.00
26.69
14.83
28.03
29.23
18.20
0.00
6.29
15.02
13.16
216
25
0.00
10.23
26.68
25.44
26.19
29.01
18.72
0.00
7.07
10.44
16.34
1.35
26
0.Do
5.34
26.72
17.67
28.34
29.44
18.18
0.00
5.86
9.40
18.25
2.51
27
0.00
11.29
26.22
1325
2838
29.30
17.45
0.00
2.63
14.62
13.42
10.22
28
0.00
14.09
3.58
1220
2850
29.44
22.12
0.00
1.84
20.57
18.41
23.37
29
0.00
-
6.92
14.23
28.69
29.48
11.55
0.00
10.31
28.44
24.68
6.76
3D
0.00
-
0.30
14.51
2860
29.41
16.70
0.00
26.41
20.46
20.87
4.59
31
0.00
-
0.00
-
28.65
-
20.32
0.00
-
13 83
25 55
TOTAL
26273
187.20
341.24
327.13
590.09
853.57
758.15
277.03
143.22
44253
550.46
224.76
4958.09
MEAN
8.48
6.69
11.01
10.90
19.04
28.45
24.46
8.94
4.77
14.28
18.35
7.25
13.58
MAX
22.77
23.83
27.53
27.69
28.69
29AS
28.95
28.79
26.41
28.44
28.39
25.55
29.46
MIN
0.00
0.00
0.D0
0.16
6.56
25.87
11.55
0.00
0.00
8.04
9.50
1.35
0.00
a�
m
nRPOW4ALS 1l B.41 AM
I
Cup:
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER: 7204.H
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska - Alternative #4
Nominal Output, P (kW):
Sao
Nominal Rated Disebarge, omr (era) =
17.8
Net Head, H„u, (it) =
451
Enemy
Outo11t
1
..
Fab
0
Mar
12186
Apr
May
Jun
Jul
Aug
Sep
cot
Nov
D. Annual
2
9601
0
M53
12833
12803
12M
0
12M
13296
0
3
137%
0
0
13127
0
0
12M
12805
14120
0
10165
12563
0
4
14342
13657
0
0
12946
12M
13230
0
68D3
1030
0
5
13919
0
115M
0
0
12927
12W
W74
0
8452
9320
a
11050
0
am
9696
0
12M
12989
0
0
10581
7904
0
7
sin
0
77M
12936
0
iW46
12a59
Ss32
0
9941
am
0
a
0
76M
12921
0
1282
12951
12363
0
10372
9601
0
9
9184
8409
0
6153
13918
0
12914
12856
' 12US
0
13195
7691
M17
10
7339
0
0
0
1010
0
12899
12829
12M
0
139D5
12M
6214
11
6662
Sam
0
0
8504
IM72
12823
I=
0
11280
12975
13774
12
6272
7131
0
0
0
9612
12M
12824
8341
0
8681
12516
12D28
13
0
0
10183
12872
13545
0
0
9388
12840
aim
14
0
0
0
9425
1280
14452
120%
0
7729
14084
0
15
0
8507
0
0
0
9486
12898
14312
0
0
6532
14162
0
16
12487
0
0
1290(1
11449
12888
13635
W16
0
0
14102
0
17
79M
0
12918
0
1304
12834
12834
7962
0
6787
14279
0
15
0
9550
0
14185
12819
12412
0
0
5904
14029
0
19
6167
0
0
6493
12%0
i2843
13736
0
0
6124
13259
0
2u
0
131M
0
0
128V
12819
12876
0
0
0
13507
0
21
0
13230
0
0
12858
12793
14021
0
0
0
14413
0
22
0
1320
0
0
12854
12513
I=ul
0
1313D
7572
12849
0
23
0
13232
0
0
12861
1087
142W
0
13504
all
11492
0
24
0
0
6172
13024
0
IM41
127%
13827
0
8)"
14268
9417
7917
25
0
12983
10799
12878
12780
12981
0
0
11046
089
0
26
0
7004
12984
1350
12866
12799
13349
0
0
7405
11817
0
27
0
0
12981
12627
128N
12763
13096
0
0
6547
12M
0
26
0
7861
13019
9620
12850
12174
12563
0
0
10721
9766
7218
29
0
0
7D026
0
8791
12840
12763
M23
0
0
139M
12994
14242
30
0
0
tD383
12825
12761
8262
0
7174
12M
13M
0
0
105%
12832
12765
12102
0
13004
136/3
13004
0
MAX 14,342 13,269 13,657 73,918 �u,um ss94 1,Tr0 8,843 11,583 2,%fi 7,041
MIN 14,186 13.00 14,462 14,120 13,504 14,258 14,413 14,212 74,452
0 0 0 0 0 12761 8.282 0 0 0 4,413 0 0
MEAN(kWt 210 IQ — 219 367 5/8 545 1 6 74 366 483 121 293
MAX(W) 596 553 $W 560 591 544 602 588 so 694 601 593 602
MIN IkW)_ 0 a n n �.. _.. _
100% rercent Daily Generator Availability
90%
630%
lox
ox
14,000
40.DD0
a6.aao
?aa0D1_............._......._..
z000 (E } € Lf
0
1�4'F�����i����t�
6 0 ' ManM in D
WaOeYN.'I441YN79Il AN 114R7A
>NHH
OWPU 2
I
I
PROJECT NAME: Alaska Rural Hydroelectric Project
PROJECT NUMBER:7204.H
CLIENT: Locher Interests, Ltd.
Site Location: Unalaska - Alternative #4
3000000 Turbine Size vs. Annual Energy Output
I I ,
' I 36" Penstock
2500000________1________J________i_______ _r ______-1-
---
3 _ 24" Penstock
00
x 20000 -------- � ' ,
4 , . I ,
0 • , • 1- • - i 18" Penstock
I �
I ,
1500000 ________1 r I
1000000 - - -• , _ _ _ _
+________y________
500000
100 200 300 400 500 600
700 800
Turbine Size (kW)
P POW4JWIMST 8:41"
N ZA
7204M
APPENDIX B: COST ESTIMATES
1. Old Harbor
I
E
Page 7
-n Ur
Page 1
APPENDIX B: COST ESTIMATES
2. Unalaska
1
Page 1
I
1
Page 1
APPENDIX C: REPORTS ON ECONOMIC AND
FINANCIAL ANALYSES
1. Old Harbor
Rural Alaska Hydroelectric Assessment:
Phase 2 Economic and Financial Analysis
of Barling Bay Creek Hydro Project,
Old Harbor, Alaska
' prepared by:
Steve Colt
Institute of Social and Economic Research
University of Alaska Anchorage
(sgcolt@aol.com)
prepared for:
Locher Interests
and
State of Alaska Department of Community and Regional Affairs
Division of Energy
January 4, 1997
'1. Introduction
This memorandum summarizes the phase 2 economic and financial analysis of the
proposed Old Harbor hydro project.
The economic analysis is essentially the same as that used in the Phase 1 final
screening analysis. Some assumptions have been revised and some uncertainties
resolved, as noted in the text below.
Thefinancial analysis provides a projection of nominal dollar cost of service and
revenue requirements with and without hydro to the Alaska Village Electric Cooperative
(AVEC) and its ratepayers.
The rest of this memo is organized into two sections. Section 2 contains the updated
economic analysis. Section 3 contains the financial analysis.
Rural Hydra Phase 2 Economic Evaluation 1/4/98 page 1
3
2. Economic Analysis
2.1. Baseline Data and Assumptions
Total Old Harbor energy requirements (net of station service) were about 713,000
kWh/yr in 1996. The system peaks in winter and the annual load is fairly constant. The
load grew at an average rate of 2.1% between 1992 and 1996, and further load growth
is important to this project's economics because the current load is far less than
projected hydro output during all months of the year.
The hydra project would provide 3,426,869 kWh/yr, which is significantly more than
current connected loads. Due to variability of streamflows and the lack of detailed water
data, the project is given no credit for firm capacity in the economic analysis. Figure 1
shows hydro output compared to current diesel generation.
rs�
Figure 1
Old Harbor Hydro Output vs Diesel Generation
350,000
300,000
250,000
200,000
150,000
100,000
50,000
�O a m =
_ _ _ _ _ - _ _ _ _ y _ _ - _ _ _ _ - _ - _ _ - _ - - - .- _ -y„ _ a
--------------------------
�—hydroE
------------- - - --- �_diesei
j
The current diesel system consists of three diesel generators with a high average
efficiency of about 13.3 kWhlgallon, measured net of station service. The. price of diesel
fuel is high at an average of $1.27 for the 1992-96 period, due to the need for river
transport.
Table 1 summarizes the baseline data and assumptions for Old Harbor.
Rural Hydro Phase 2 Economic Evaluation
1/4/98 page 2
7
C
Table 1: Old Harbor Baseline Economic Data and Assumptions
Energy RequirementsActual
1Actual
'
o e
eneration
Yr
!748
ess: Station Svc
4.7%
35
1=13usbar Requirements I
yr
!Peak LoadatStation)
ti
Load actor
i0.5501
a
jPeak Loadat us ar
I
4
Fuel rices and Ltheiency I
i
ITotal FuelCost -
13521
1I otal (iallons use j000
gal
'Average Price 1
ga
IM—OU&I 1997 Base Price
gal
I1.271
vg Busbar Efficiency 1kWh/gal
. }
I Model 1997 Base Efficiency
kWhlgal13.2
Financial Parameters
1
I
Nominal a nterest Rate
a
o
New Uebt Issuance Cost o ot
tace va u
, a
Onflation Rate
o
3.0%1
arget TIER Ratio
2.0011
PlantAdditions: Book
Lite : o
e t
a qui
ew iese 1
01
0
New y ro 1
0
0
JAII
other New Plant I2uiQ
I
o 1
Tw-.-Diesel. Operating Parameters
Max
hours
Initial Cum
1 iretime
IKVV
j
per yr
Hours
ours
nitCummins LTA10
142
6,000
nit at 33061971
4
,
Unit at
ew Diesel Units 1200
6,000
UI
ni must -run time
hrs 1
Diesel only nonfuel
including overhauls:
yr
New & ReplacementDiesel Costl
ew Diesel CapitalCost
i450
New Ulesel Etticiency
gal
omposi a Overhaul cos 1
or UU H arbor
0.00
er nontuei vanable cos I
U. U 0I
y ro Operating Parameters
1
Hydro Energy Capability
MWn/yr
13,427
-FFy
ro ective Capacity
y ro ec Five availability
%
96.5%
Hydro+Diesel Combined
non ueM&M (incl Uhauls)yr
source: VLUHAKbZ.ALS
Rural Hydro Phase 2 Economic Evaluation
114198 page 3
New Treatment of nonfuel O&M. The treatment of nonfuel O&M for both diesel and
hydro in Old Harbor has changed since the phase 1 analysis. On the diesel side, the
most important change is the treatment of diesel overhaul costs. In phase 1, these
costs were calculated based on the number of hours that the diesel units are on. For
this (phase 2) analysis 1 assume that essentially all overhaul costs are avoided by the
hydro project since it provides all energy except when it is down for scheduled or
unscheduled maintenance. The reason for the change of method is that using a
reasonable per -hour overhaul cost calculated from engineering estimates of the cost of
overhauls seems to greatly understate the actual documented total amount of nonfuel
O&M. On the hydro side, the project team refined our cost estimates for the hydro
system into specific line items. This allowed me to isolate the portion of hydro O&M
expense that is additional to the routine maintenance that could be assigned (at zero
incremental cost) to the existing operator.
The result of this exercise is shown in Table 2.
Table 2
Votal Costna
ysm of
ar or Nontuel O&M Withan out y ro
(a) I (b)
I (c)=-((b) x (a)) (d) I (e)=(a)+(c)+(d) 11
(i=(c)+(d)
Total
Cost JAS3UMED
Reductions Additions j TotalCost
Net
Without I o Avoided
rom using due to I With ;
uitterence
xpense
ategory
y ro y y
ro
Hydra Hydra 1 Hydra I
due to Hydra,
Buildings
5,933
0.0%1I
relg t
o
1
4
Materials
. o
Isc
U.
o
I i3,058
Operator
i24,905
0.0%11
! 1
Other Labor
o
I 9,600 9,600 I
ver au
. 0
1 0I
rave
I
o
j 15,900
ota
!
I 37,000 1 73,197I
i
I I I
notes:
i out y ro O&M
from-AVEG data tor Old Harbor, and 1994,
reported
Iin
Polarconsultppen
ix F. j
Percent reductions
due to hydro based on professional judgment at
project
I economist.
1
13)
itions due
to Mydro
based
on professional judgment at project team.
source: j
see
I I {
One final adjustment to the data and model is to remove the annual cost of lube oil
(about $1,400) from the totals above and express it as a variable cost on a per kWh
basis. Lube oil at 2 mills per kWh is a trivial component of the average total nonfuel
O&M cost which averages 10 cents per kWh.
Rural Hydro Phase 2 Economic Evaluation 114198 page 4
Assumptions about Timing. The project is assumed to be constructed in 1999 and to
go online on January 1, 2000. All construction outlays are modeled as if they were
made on January 1, 1999. This is a good approximation of the actual procurement
pattern, which would involve procurement and outlays from about July 1 1998 through
December 1999 in order to achieve the online date of January 1, 2000.
2.2. Old Harbor Critical Assumptions
Table 3 summarizes the values used for the critical assumptions. In this analysis, the
real discount rate and the with -hydro 0&M amounts are treated as certain, while the
two values for hydra capital cost result from a future policy judgment. Thus, only load
growth and fuel price growth are treated using a range of values with probabilities
attached to each.
Table 3: Old Harbor Critical Assumptions
(probabilities below each)
E units I ow I Mid I High
Loaa GrowthI
j
1Energy Reqts and Peakrowt a yr
IMI
2.0% I o
j
1
I I I
I
uel Price Growth j o yr
1 0.0%1
0.5%1
1.5%
I
Real iscoun Rate I
o yr
I not
1.94%1
not
I
used
1,001
use
I
1
Hydro Capital Costnot
-nu
1.UU1
use
I
Combined y ro+ iese
yr
not
71,556
1 not
JFwith hydro)1
use
use
Load growth is important for this project. Growth has averaged 2.1 % from 1992-96, but
load declined during two of the four years.
Fuel price growth (in real dollars) could occur because of increasing worldwide demand,
rising production costs, carbon taxes, or the imposition of more stringent marine
transportation standards. Note that growth in real fuel prices also has the same effect
on the analysis as a possible reduction in fuel efficiency due to more stringent air
quality standards. Because the price of crude oil represents only about 35% of the
delivered cost of utility diesel to Old Harbor, the midrange assumed rate of increase
(0.5%) is roughly consistent with a 1.5% annual increase in crude prices.
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 5
1
The real discount rate of 1.94% is derived from the assumed nominal interest rate of
5% and the assumed inflation rate of 3%. (The exact calculation is:
.0194 = (1.0511.03) - 1). The results present dollars discounted back to 1997.
The low value for hydro capital cost is based on a force -account approach using local
labor. The higher value for hydro capital cost is based on a contractor approach.
1 The with -hydro combined system fixed O&M is the same as that derived in Table 2
above, except that lube oil has been removed from the Table 2 total and treated as
variable.
2.3. Old Harbor Economic Analysis Results
Range of Results. Under mid -range assumptions about load and fuel price growth, the
hydro project has a present value of net benefits of about +$625,000 using the low
capital cost, and net benefits of-$410,000 using contractor costs. (Subsidies in the form
of grant funds are not considered in these figures.) Under the most pessimistic set of
assumptions, the net benefits are -$1.3 million. Under the most optimistic assumptions,
the project has positive net benefits of about $2.1 million. Table 4 summarizes this
range of results.
Rural Hydro Phase 2 Economic Evaluation
Y 114198 page 6
I
Table 4
ResultsSummary: Old Harbor
Net Benefits o y ro, ea
over
years
I
Force Acct
i
Contractor i
mos
mos
os ,
Costs, I
optimistic
pessImis is
mid -range 1
mi-range I
uses
uses
assumptions;
assumpionsi
force ace1
contractor)
Case name
mmm m
mmmmm
hhmim 17
mmm
Critical assumptions:
I
Loaa Growth.
fl
o I
3.0%1
1.0%
ea Fuei PriceGrowth
. o i
0.5%1
oI
o
Real iscount Rate
1.9%1
1.9%i
o f
o
Hydro Capital Cost
a .
it - y ro Fixeda
E
esu1997-2034)
Diesel -Only system
I
I
Diesel Fuel
I
Diesel nonfuel aria e
65,979
45,849
Diesel apace
i
I ys em ixe
2,310,152
otal Costof iesePower
i o I
With Hydro
I
I
Diesel Fuel
iese non ue Operating
Diesel apace
1
y ro Construction
1
,
ys em ixe
1
,
1,986,933
Totalos with Hydro Power
1
,
i
Net Benefitof Hydro roject
I
,
(parentheses indicate negative numbers)
1
1
Probability Distribution of Results. Because there are only two critical assumptions
with probabilities attached to three different values for each assumption, there are a
total of 9 cases forming the probability distribution. Figure 2 shows this distribution
assuming the high construction cost (contractor basis).
Rural Hydra Phase 2 Economic Evaluation
1 /4/98 page 7
Figure 2:
Probability Distribution of Net Benefits: Contractor Cost
Probability Distribution of Net Benefits: Old Harbor
IZ prob
0.35
0.3----- - - - - -- -----------------------
0.25--___-__------- - - - - -------- - - - - --
0.2.------ - - - - -y---- - - - - --
m
0 0.15----- - - - - -- ----------9-------------
a
0.1. - - - -----r---- - - - - --------- - - - - --
R
J
0.05 ---- -- ---- - - -------- - - - - --
0
M QL V: N Q N V CD CO O
0 0 09 0 0 0 0 0 r
Net Benefits (million 1997$)
Using the low capital cost (force account basis) assumption increases the net benefits
of all 9 cases by about $1 million. Figure 3 therefore shows the same distribution as
above but shifted $1 million to the right.
Figure 3:
irobabillty ui;stribution of Net lenefits: Force Account Cost
Probability Distribution of Net Benefits: Old Harbor
0.3
0.
0.2
N Q f0 CR O N d' U0 QD
Q 4 O O
Net Benefits (million 1997$)
pr°b
Rural Hydra Phase 2 Economic Evaluation 114198 page 8
2.4. Break-even Analysis
Load Growth and Fuel Price Growth. In this analysis the major uncertainties are the
future growth in loads and real fuel prices. Figure 4 shows the combinations of these
two variables that lead to net benefits of zero, under both the high and low construction
cost assumptions. To fix the interpretation of this figure, consider the lower line, which
shows breakeven combinations for the low (force account) construction cost. This line
crosses the horizontal axis where load growth equals about 1.0%. This means that the
combination of 1.0% load growth and flat (real) fuel prices is sufficient to produce zero
net benefits with hydro. All combinations above each line yield positive net benefits; all
combinations below each line yield negative net benefits.
Figure 4
Breakeven Combinations of Load Growth
E
and Real Fuel Price Growth
4.0% construction Cost 3.7 million
3.0%--------------- ---- - - - --. $_Construction Cost 2.6million
2.0°%.---- - - - - -
-
----------------------
U'y 1.0%--------------- '
m
-1.0%------- - - - - -- - - - - -------- - - - - --
U- -2.0%---------------------------------- ---
4 -3.0%
II 0.0% 1.0% 2.0% 3.0%
Load Growth
Discussion. The Old Harbor analysis is well summarized by Figure 4 above. It shows
that under the assumption of a low construction cost, the project is economic under a
wide range of load growth and fuel price growth rates. If contractor labor is used and
the construction cost is consequently high, there are not very many plausible
combinations yielding positive net benefits. However, since the project has substantial
excess energy production at zero marginal cost, any immediate and substantial
t increase in loads, such as off-peak heating or fish processing, would dramatically
improve the economics.
This analysis differs from the phase 1 evaluation in two ways. First, the construction
cost estimates are about $1.6 million higher. Second, this increase is partially offset by
a revised estimate of O&M costs which suggests that nonfuel O&M for the Old Harbor
power system is lower with hydro than it is without. However, this 0&M savings has a
Rural Hydro Phase 2 Economic Evaluation
114/98 page 9
I
present value of only about $300,000. This is not enough to offset the increase in
construction costs. Therefore, the net economic benefits of the Old Harbor project are
reduced across the board by about $1 million from those reported in phase 1 of this
study.
2.5. Old Harbor Financial Analysis: Assumptions
Purpose of the Financial Analysis. The purpose of the financial analysis is to tame
account of the timing of actual cash flows -- especially debt service -- and to put these
cash flows into the broader context of the utility's overall finances. One reason for doing
this is to see if the timing of costs and benefits requires changes in rates in order to
cover expenses. In particular, there are three ways that conventional debt financing and
ratemaking can lead to initial rate increases when a capital -intensive project such as
hydro is put on line. These problems are listed in order of increasing importance for
rates:
Problem 1: Conventional debt usually requires constant nominal dollar payments to
repay debt. Such payments are declining when expressed in real dollars, which means
that the real capital cost payments are front -loaded onto the early years.
Problem 2: In
addition to the front -loading caused by constant nominal debt service,
conventional utility ratemaking usually calculates revenue requirements using
depreciation plus interest. Since first -year depreciation greatly exceeds the first -year
component of debt service that represents principal, this ratemaking practice leads to a
further potential for front -loading of costs onto rates.
Problem 3: Lenders (or political regulators) may require that expected utility revenues
be sufficient to provide a "cushion" of positive net earnings that allows for some volatility
in actual revenues without jeopardizing the ability to make interest payments. Typically
this is expressed as a required ratio of:
TIER= Times Interest Earned Ratio = (Net Income + interest)/Interest
For example, the minimum required TIER imposed by the federal government on
borrowers from the Rural Utilities Service is 1.5. Golden Valley Electric Association is a
regulated cooperative and has an approved target TIER of about 1.8.
Scope of the Financial Analysis. The issues above must be addressed on a utility -
wide basis. The financial analysis model is therefore designed to project the expenses
of the entire AVEC utility system in a simplified way that captures the following key
assumptions:
Rural Hydra Phase 2 Economic Evaluation
1/4/98 page 10
• Some costs are relatively fixed, so that ongoing load growth tends to keep inflation -
adjusted costs down.
• The hydro project is a small piece of the total AVEC system. It is important to
consider this relationship to the total system because the cost (and benefits) of
hydro will be shared by all AVEC members.
• AVEC has historically borrowed at subsidized interest rates of about 2%. Current
rates are about 5%. This puts some "background" upward pressure on rates with or
without hydra.
• Customer class structure is assumed constant, so that growth in loads translates
directly into revenue growth at existing rates.
Determination of Revenue Requirements, The analysis determines annual revenue
requirements for the entire electric system with and without the hydro project. First, the
cost of service is calculated using financial accounting costs. I call this the accrual basis
cost of service. To the cost of service is added the requirement for a cushion of net
income, or "margin" sufficient to provide for the target TIER.
Fuel
+ Other Operating
+ Depreciation
+ Interest
Cast of Service
+ Margins.
= Revenue Requirement
Specific Financial Assumptions. The following specific assumptions, repeated from
Table 1 above, are used:
Fin-a—ndal Parametem
IN-Ra e t Interest ate
o
a
New Uebt issuance Cost
a of face va u
a
Inflation ate
3.0%J
arget I I LK Ratio
2.001
Plant Additions.
Book Life
o e t
I o quiff
ew ifesel
101
a
a
ew Hydro
30
o
ATFo er ew an
o
a
The debt issuance cost is set to zero assuming the continued use of traditional
financing sources. The average 20-year life of all other electric plant was determined
from analysis of current depreciation expense relative to plant amounts. The debt
repayment term is the same as the book life for each type of plant. Constant nominal
payments of [principal + interest] are assumed.
I
Rural Hydro Phase 2 Economic Evaluation
1/4/98 page 11
1
In addition to these parameters, I use the following key assumptions to project future
expenses:
• Fuel expense increases with load and inflation. (No further increase in fuel efficiency
is assumed). The same load growth used for Old Harbor is used for the rest of the
system in each run.
• The economic model already projects diesel generator and hydroelectric plant in
service for Old Harbor. To project all other plant (including production plant in all
other villages), I assume that this other net plant in service grows with load. On a
nominal -dollar basis, required net plant also grows with inflation.
• Admin & General costs are fixed in real dollars. They grow in nominal dollars with
inflation. Distribution 0&M is also fixed in real dollars.
• Production nonfuel operating costs (mostly labor and overhauls) are partly fixed.
They grow in real terms at half the rate of load growth.
2.6. ' Old Harbor Financial Analysis: Results
' Revenue Requirements without Hydro. Table 5 shows the projected cost of service
for the system without hydro. The main forces acting on all costs are 3% inflation and
2% load growth.
7
Table 5:
AVEC Revenue Requirements Without Hydro for mid -range assumptions
(nominal dollars, case mmmmm)
Gost of Service
Without Hydro
1997
2002
2005
2010
2020
2030
Fuel
4,717,533
6,190,593
7,286,897
9,562,246
16,466,242
28,354,962
+ Other Operating
8,394,901
10,023,000
11,151,224
13,327,714
19,074,868
27,370,086
+ Depreciation
3,202,178
3,546,551
3.880,052
4,681,914
7,603,948
12,029,297
+ Interest
769,430
1,811,043
2,417,581
3,407,304
5,526,295
8,584,118
= Cost of Service
17,084,043
21,571,186
24,735,854
30,979,179
48,671,353
76,338,463
+ Margins
789,430
1,811,043
2,417,681
3,407,304
5,526,295
8,584,118
= Revenue Requirement
17,853,473
23,382,229
27,153,536
34,386,483
54,197,648
84,922,581
Figure 5 shows projected revenue requirements under utility basis accounting without
hydro. The figure shows how a diesel -based utility has relatively low capital costs and
relatively high operating costs.
Rural Hydro Phase 2 Economic Evaluation 114198 page 12
Figure 5:
Revenue Requirements, No Hydro, midrange assumptions
AVEC system revenue Reqts -- No Hydro
120,000,000
100,000,000 ---------------------------
80,000.000 ------_--- Margin
- - --
60.000.000 -----------------------------------
40.000,000- ---- -- --------- - - - - --
20,000.000 Othr Op
Fuel
0 .
n (n M LO M uO n M
r a) m O O O O O r r N N N N N [7 C''1
Q� Q1 O O O O O O O O O O O O O O O O O
r N N N N N N N N N N N N N N N N N
Interest
Deprec
E Interest
M Deprec
p Othr Qp
Difference in Revenue Requirements due to Hydro. With this context established,
we now consider the difference in revenue requirements due to the hydro project, under
various sets of assumptions. Table 6 summarizes these differences for the midrange
assumptions (case mmmmm).
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 13
1
Table 6:
Differences in AVEC System Revenue Requirements due to Hydra
midrange assumptions, case mmmmm
ney increases (Decreases) in
Gost Due to
Hydro
1997
2002
2005
2010
2020
2030
Fuel
0
(86,965)
(102.366)
(134,330)
(231,317)
(398,328)
Other Operating
0
(17,195)
(18.907)
(22,165)
(30,557)
(42,325)
Depreciation
0
129,288
129,288
129,288
83,891
(21,209)
Interest
0
184,730
174,078
152,463
78,260
(10,830)
Cost of service
0
209,859
182,093
125.257
(99,722)
(472,692)
Margins
0
184,730
174,078
152,463
78,260
(10,830)
Revenue Requirement
0
394,589
356,171
277,721
(21,461)
(483,522)
Average CosfComparison
Cost of Service
1997
2002
2005
2010
2020
2030
Without Hydra
37.6
43.0
46.5
52.7
67.9
87.4
With Hydro
37.6
43.4
46.8
52.9
67.8
86.9
Difference
0.0
0.4
0.3
0.2
(0.1)
(0.5)
Revenue Requirements
Without Hydro
39.3
46.6
51.0
58.5
75.6
97.2
With Hydro
39.3
47.4
51.7
59.0
75.6
96.7
Difference
0.0
0.8
0.7
0.5
(0.0)
(0.6)
o Changes due to Hydro
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
1.0%
0.7%
0.4%
-0.2%
-0.6%
Change in Revenue Req't
0.0%
1.7%
1.3%
0.8%
0.0%
-0.6%
a-- U1W 1n1 V44-AM Sf1VUL ne1_4en
The economic analysis above showed that in this case (mmmmm) the hydro project has
net economic benefits of-$410,000 in present value. Reflecting this fact, the table
shows that the annual cost of service is higher with hydra until at least 2010. The actual
"crossover year" during which with -hydro cost of service fails below without -hydro cost
for case (mmmmm) are as follows:
Cost of Service Revenue Re 'ts
2016 2021
Figure 6 summarizes what is going on. It shows the difference in the cost of service (as
bars) and the main components of that difference (as lines). Since margin=interest for
the assumed target TIER of 2.00, the lines for interest and margins lie on top of each
oher. There is a spike in year 2001 due to the interest and associated margins on the
hydro outlay. In 2002, depreciation jumps and fuel prices drop as the hydro plant is
placed in service. During the first 14 years of operation, the interest plus depreciation
on the hydro project exceed the operating savings, which are almost entirely fuel.
Throughout the project life interest declines and depreciation stays constant, while fuel
savings increase with inflation, load, and (in this case) 0.5% real growth in fuel prices.
Rural Hydro Phase 2 Economic Evaluation
114198 page 14
I
Figure 6:
Components of Difference in Revenue Requirements due to Hydro
mid -range assumptions, case mmmmm
Differences in Revenue Requirement due to Hydro
(Accrual Basis Acounting, Margins Included)
6oa,000
400.000
200,000
0
E
5 (200,000)
(400,000)
(600,000)
(&00,000)
rr M M LO n rn n LO n rn r M LO n rn M
a) co O O O O O r r N N N N N c] Cn
rn rn 0 0 O 0 0 0 O 0 0 0 0 0 0 0 O 0 O
r r N N N N N N N N N N N N N N N N N
year
i_ Margin
_ Interest
�— Deprec
Other Op
Fusel
ResuEts for Other Sets of Assumptions. Table 7 shows the difference in cost of
service for all six combinations of construction cost and fuel price escalation. The main
conclusion to note is that with the low (force account basis) construction cost, the cost
of service drops immediately under all fuel price scenarios, because the first year fuel
savings exceed the first year sum of hydro depreciation plus interest.
Rural Hydro Phase 2 Economic Evaluation
114198 page 15
Table 7: Summary of Revenue Requirement Impacts of Hydro
Old Harbor
Financial ResultsSummary:
Increase(Decrease) in
Average Revenue Requirement
due to Hydro
(includes margins
Load Fuel
Current Dollars
% Change from Diesel-on!
Growth rowt
2002
2005
2010 i 2020
2030
2002 } 2005
2010 1
2020 2030
Contractor cost
}
mid Clow
3 6, 73 1
360, 116I
_ ..) I J,
(473,073)
o 1.3%1
0.8%1
i
0.0%
- .5%
amid
394.589
(_ .
(433,522)
. ei a o
o
_ WO
- , a
high
3
33 +
3I,' ]
of 1.3%1
0.7%1-0.1%
- 0. 7:a
Force account cost
mid low
_
f
] ,3 --
23,
of 0.9%1
0.5%
-o.2%
- .] o
Imid
247,802
], ]D
_,_
3,5
of . o
o
- . o
- . o
thigh
243,399
,_
131,474 (171,450)3r,
]
o O 0. o
- o
./ a
Most Optimistic (uses Force Acct Cost)
high I high
-Most
1 -238,733
1 198,0.')6,3
I (230,014)
o f o U._ a-
a-
o
Pessimistic uses Contractor cast
low low
400,893
1 367,7851
jU1,603 63,694
(36j,995)]a
j o
1.0%1
o-
a
1 Discussion of Results. The financial analysis shows that even under themost
optimistic assumptions, average AVEC revenue requirements would increase
systemwide by about 1 percent when the project first goes online. Under the most
pessimistic assumptions, revenue requirements would increase by almost 2 percent. A
significant portion of this increase is in the form of required margins to meet a TIER of
2.0. These margins ultimately accrue to the benefit of member -ratepayers, but they
nonetheless result in higher current rates.
Even when margins are excluded, and using the low (force account) cost basis, under
mid -range assumptions about load and fuel price growth the systemwide cost of service
is higher with hydro until the year 2012. Nonetheless, the relative change in revenue
requirements is still minor, as shown in Figure 7.
Rural Hydra Phase 2 Economic Evaluation
1I4I98 page 16
Figure 7:
Average AVEC revenue Requirements without and With Hydro
(systemwide, includes margins)
120.0
100.0
:IIM
3
m 60.0
a
h
c
40.0
20.0
0.0
C7 CO
_ NU') CO Q � o M
M O 4 O O O O O Q Q Np p
i T N N N N N N N N N N N N
�I
i
without hydro
....... w ith hydro
Rural Hydro Phase 2 Economic Evaluation 114/98 page 17
APPENDIX C: REPORTS ON ECONOMIC AND
FINANCIAL ANALYSES
2. Unalaska
1 Rural Alaska Hydroelectric Assessment:
Phase 2 Economic and Financial Analysis
of Hydroelectric Projects in Unalaska, Alaska
prepared by:
Steve Colt
Institute of Social and Economic Research
(sgcolt@aol.com)
prepared for;
Locher Interests
and
State of Alaska Department of Community and Regional Affairs
Division of Energy
.January 4, 1997
1. Introduction
This memorandum summarizes the phase 2 economic and financial analysis of two
candidate hydro projects in Unalaska:
Pyramid Creek Alternative #4, a 600 kW project
Pyramid Creek Alternative #1, a 50 kW power -recovery project
The economic analysis is essentially the same as that used in the Phase 1 final
screening analysis. Some assumptions have been revised and some uncertainties
resolved, as noted in the text below.
The financial analysis provides a projection of nominal dollar cost of service and
revenue requirements with and without hydro to the City of Unalaska and it's
ratepayers.
Section 2 contains the updated economic analysis. Section 3 contains the financial
analysis.
Rural Hydra Phase 2 Economic Evaluation 1I4198 page 1
2. Economic Analysis -- Pyramid Creek Alternatives #4 and #1
3
2.1. Baseline Economic Data and Assumptions
Total energy requirements (net of station service) in Unalaska were about 28,746,000
kWh in 1996. The load far exceeds the output of the proposed Pyramid Creek projects;
load growth is unimportant. The system peaks in winter and the annual load is fairly
constant.
This analysis mainly considers Pyramid Creek Alternative #4, which would have a
nominal rated power output of 600 kW and an energy capability of 2,570,033 kWh per
year. (Section 2.5 considers the economics of Pyramid Creek #1 power recovery
project.) Figure 1 shows the output of the project compared to current diesel
generation.
Figure 1
Pyramid Creek (#4) Hydro Output vs Diesel Generation
3,000,000
2,500,000
2,000,000
1,500,000
Y
1,000,000
500,000
f hydro
-------------------------
- diesel i
----------------------------------
c -0 `a n }. c 5 a� a > c)
The current City utility diesel system consists of 7.5 MW of installed capacity, with a
current average efficiency of about 13.6 kWh/gallon (measured after station service).
Table 1 summarizes the baseline data and assumptions for Unalaska. Project timing
assumptions are not shown in the table
Rural Hydro Phase 2 Economic Evaluation 114198 page 2
I
Table 1: Pvramid 94 Ra--qPiinn Fr`nnnmir r1n+-% nnr4 A�r.,,,.....s:.
Energy Requirements
;Actual
Actual o e
i
eneration
! yr
25,487
29,574
esS: tatlon VC
_ a
us ar equiremen s
yr
4,28,746
i
j Peak LoadatStation)
Load tactor
1
ea oaa at busbar)
1
Fuel Prices and Efficiency
I
ota Lie ost -
ota a ons use
I000 ga
verage nce
ga
. r
o e ase nce
Vgalr
Vg Fusbar Efficiency
ga
o eBase Effictizrcy
ga
Financial Parameters
I
em3n2e t nterest ate
I a
-6t
o
ew e t Issuance Cost
; o face va u
2.0%
r- 1 n anon Rate
a
_
o
arget 71 E R R atio
I ant loons:
Boo i e
o e t
o ui
New iese
a
a
fNew Hydro
I of er New Plant
I
o,
a.
Mesel Operating Parameters
;
ax hours
per yr -7
Initial Cum Litetime
Hours i ours
nit 1, Exist
i
n: x1st
UnitExist
New Diesel Units
2,500j
Unit J must -run time
rs
175
lRequired Reserve argin
a
o
I
ew & ReplacementDiesel Cos
I
[New Diesel CapitalCost
New Diesel Efficiency
omposite Overhaul cost
kWhigal
[incl-uded in fixed
t er non ue vana e u e of
-Operating
Hydro arame ers
i
y ro nergy apa i i
—iv
yr
2,570
y ro E Fecte Capac1
Hydra artective availability
9 8. Uo
et additional nonfuel
ue to hydro
yr
.A Assumptions about Timing. The project is assumed to be constructed in 2001 and to
go online on January 1, 2002. All construction outlays are modeled as if they were
Rural Hydro Phase 2 Economic Evaluation
I
1/4/98 page 3
made on January 1, 2001. This is a good approximation of the actual procurement
pattern, which might involve procurement and outlays from about July, 2000 through
l December 2001 in order to achieve the online date of January 1, 2002.
1
2.2. Pyramid #4 Critical Assumptions
Table 2 summarizes the values used for the critical assumptions. In this analysis, load
growth is unimportant, the real discount rate and the with -hydro net O&M amounts are
treated as certain, and the two values for hydro capital cost result from a future policy
judgment. Thus, only fuel price growth remains to be treated using a range of 3 values.
Table 2: Pvrnmiri Crank Iffdl rr�+�►-�� eccw,�+:�..,..
Probabilities below each) 3 I
units ow I I �g
Loadro I
i nergy Keqts and PeaKrowt a yr
not
o
not
' use use
I
ruel Price GrovAn 9/olyr o; U. o I o
.
I i �
Real iscoun a e o yr
not
o
not
I ! used 1.001
!
use
I
Hydro Capifil CostI I
not
I i
used
I ! I
Net nonfu—e—M&M clue to y ro yr
T i
not
used
0
1.uu1
1 not
use
Load growth is not important for this project.
Fuel price growth (in real dollars) could occur because of efforts to address greenhouse
gas emissions through taxation of carbon -based fuels, or the imposition of more
stringent marine transportation standards. Note that growth in real fuel prices also has
the same effect on the analysis as a possible reduction in fuel efficiency due to more
stringent air quality standards. Because the price of crude oil represents only about
50% of the delivered cost of utility diesel to Unalaska, the midrange assumed rate of
increase (0.5%) is roughly consistent with a 1.0% annual increase in crude prices.
The real discount rate of 2.91 % is derived from the assumed nominal interest rate of
6% and the assumed inflation rate of 3%. (The exact calculation is:
.0291 = (1.0611.03) - 1). The results present dollars discounted back to 1997.
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 4
I
a
The low value for hydro capital cost is based on a force -account approach using local
labor. The higher value for hydro capital cost is based on a contractor approach.
For the Unalaska analysis an incremental approach to nonfuel O&M makes more sense
than a computation of total nonfuel O&M with and without hydro. The City is confident
that existing labor can be redeployed for routine maintenance. Beyond this, the project
team feels that being a larger utility. Unalaska should have less of a need than Old
Harbor for imported skilled labor for hydro 0&M. For this reason we should expect that
the incremental 0&M associated with hydro would be less than in Old Harbor.
Balancing this factor, however, is the fact that it is unlikely that the small amount of
hydro energy (relative to total diesel output) will result in any reduction in diesel
overhaul costs. Considering all these factors and applying them to the Old Harbor case
where the net nonfuel 0&M due to hydro was-$13,000 per year, I arrive at a value of
zero for the net O&M due to hydro in Unalaska.
2.3. Pyramid #4 Economic Analysis Results
Range of Results. The Pyramid Creek #4 project has significant positive net benefits
under all plausible assumptions. Under mid -range assumptions about fuel price growth,
the project has a present value of net benefits of about +$1.6 million using the low
capital cost, and net benefits of *$1.0 million using contractor costs. Under the most
pessimistic set of assumptions (zero fuel price growth and high construction cost), the
net benefits are still +$0.7 million. Under the most optimistic assumptions (1.5% fuel
price growth and low construction cost), the project has positive net benefits of about
$2.2 million_ Table 3 summarizes this range of results.
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 5
Table 3:
Results Summary: Pyramid Creek #4
Net Benefits of Hydro, Real $ NPV over 35 years
Force Acct
Contractor
most
most
Costs,
Costs,
optimistic
pessimistic
mid -range
mid -range
(uses
(uses
fuel growth
fuel growth
force acct)
contractor)
Case name
mmm m
mmmmm
m h mim
m mmm
Critical assumptions:
Cl: Load Growth
2.0%
2.0%
2.0%
2.0%
C2: Real Fuel Price Growth
0.5%
0.5%
1.5%
0 0%
C3: Real Discount Rate
2.9%
2.9%
2.9%
2.9%
C4: Hydra Capital Cost
1,557,900
2,177,800
1,557,900
2,177,800
C5: With -hydro Fixed O&M
0
0
0
0
esu -
Diesel -Only System
Diesel Fuel
58,729,489
58,729,489
71,333,896
53,513,931
Diesel nonfuel Variable
1,943,222
1,943,222
1,943,222
1,943,222
Diesel Capacity
3,747,387
3,747,387
3,747,387
3,747.387
System Fixed O&M
0
0
0
0
Total Cost of Diesel Power 64.420,098 64,420,098 77.024.505 59,204,541
With Hydro
Diesel Fuel
Diesel nonfuel Operating
Diesel Capacity
Hydro Construction
System Fixed O&M
Total Cost with Hydro Power
Net Benefit of Hydra Project
(parentheses indicate negative numbers)
55,765,038
1,845,485
3,747,387
1,388,881
0
62,746,792
55, 765, 038
1,845,485
3,747,387
1,941,527
0
63,299,438
67,716,691
1,845,485
3,747,387
1,388,881
0
74,698,444
1,673, 307 1,120, 661 2,326, 061
50,822,380
1,845,485
3,747,337
1,941,527
0
58,356,780
847,761
Probability Distribution of Results. There are only 3 possible outcomes for each
choice of construction regime (force account or contractor). Hence a probability analysis
is not necessary. Table 4 summarizes the net benefits for all 6 possible combinations of
critical assumptions.
Rural Hydro Phase 2 Economic Evaluation 114198 page 6
Table 4:
Summary of Net Benefits as a Function of Fuel Price Growth
Net Benefits
of Hydro
High (Contractor) Construction Cost:
Low Fuel Price Growth 0.0% 847,761
Mid 0.5% 1,120,661
High 1.5% 1,773,415
Low (Force Account) Construction Cost:
Low Fuel Price Growth 0.0% 1,400,407
Mid 0.5% 1,673,307
High 1.5% 2,326,061
Effect of Strearnfiow Restrictions. Possible streamflow restrictions of 1,2, and 3 cfs
minimum flow reduce hydro output by between 5 and 15 percent. This reduction
reduces the gross benefits similarly and the net benefits by relatively more. Table 5
shows the effects of the restrictions on project net benefits. The table shows that the
projett`remains viable with the restrictions.
Table 5
Effect of Streamflow Restrictions on Net Benefits
Net Benefits of Hydro, Real S NPV over 35 years
Force Acct
Contractor
most
most
Costs,
Costs,
optimistic
pessimistic
mid -range
mid -range
(uses
(uses
fuel growth
fuel growth
force acct)
contractor)
Case name: mmm m
mmmmm
mtim m
m mmm
ream ow:
No Restrictions
1,673,307
1,120,661
2,326,061
847,761
Min 1cfs
1,523,059
970,413
2,143,785
710,903
Min 2 cfs
1,349,059
796,413
1,932,694
552,410
Min 3 cfs
1,194,226
641,580
1,744,856
411,376
2.4. Break-even Analysis and Discussion
No breakeven analysis seems useful for Pyramid #4 because the net benefits are
substantial and positive for all plausible sets of assumptions.
Discussion. Pyramid Creek #4 appears to be a very solid project. It does not depend
- for economic feasibility on load growth or fuel price increases or any presumed capacity
deferral benefits. Furthermore, benefits to the City of Unalaska from reduced air
emissions are not considered in coming to this conclusion.
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 7
2.5. Unalaska #1 (50 kW Power Recovery Project) Results
Assumptions. This project would produce 319,128 kWh per year using water already
diverted to the City water supply system. The project has no firm capacity. All other
assumptions are identical to those for alternative #4 as discussed above. The cost
estimates are $392,500 (force account) and $509,000 (contractor).
Range of Results. This project only produced net benefits under the low construction
cost assumption and positive fuel price escalation. Table 6 summarizes the range of
results.
Tnhlr, A
ResultsSummary: Pyramid Creek
e ene i
o yro, ea over
35 years
orce
most
Costs,
mid -range
Costs,
mi-range I
I pessimistic
uses uses
-case
fuelgrowth
fuel grow ;
Torce acc
contractor)
name I
Critical assumptions:
mmm m
I mmmmm I
m m m I
m mmm
LOaCI UrowthI
0
2.0%1
a
IC2: R—eaTFuel Price Growtho
_ o
o
. Real Discount Kate
2.9%1
2.9%1.
o j
2.9%
i 4: y ro Capital Cost I392,500
509,000i
f . it -yro ixe I
U
0
I
--
Results:I
iese - n y System
EMesel Fuel
1 31
iese non ue aria e
,
I Ease apace !
,nT
o aCost a Rese ower
a y ra
>ese ue
,
17-9,714
iese nonfuel Operatin1,931,085,
Diesel apace
y ro ons ruc ion
e ueo Hydro
otal Costwi yro ower
Net benefito yro ro�ec
(parentheses indicate negative numbers)
QQUI%,a. [ V%MIULYI.ALJ, bII=L Sef15
Rural Hydro Phase 2 Economic Evaluation
114/98 page 8
-� Results with Different Assumptions. There are only 3 possible outcomes for each
choice of construction regime (force account or contractor). Hence a probability analysis
is not necessary. Table 7 summarizes the net benefits for all 6 possible combinations of
critical assumptions.
Tapia 7
Summary of
NetBenefits as a
Unction o ue rice row
(Unalaska
Alterna ve
Power ecovery
et ene its
o y ro
High (Contractor)
Construction Cost.
Low F uel
P nce G rowi i U.0%
°
High
_ °
ow orce ccountConstruction ost:
LOW F-uel
Hrice rowt
°
ivila U.
b°30,324
High .
°
-,IVU:E . parenzneses inaicate negative numbers
source: PYRMID2A.XLS, sheet `sees'
Discussion. Although this project benefits from having the associated mob/demob cost
allocated to the larger #4 project, it is still only marginally economic. The project's
output is much lower than the amount assumed for the phase 1 analysis. It is this drop
in output with no corresponding decline in construction cost that accounts for the
difference between this analysis and the generally positive economics found during
phase 1.
I Financial Analysis
3.1. Pyramid #4 Financial Analysis: Assumptions
Purpose of the Financial Analysis. The purpose of the financial analysis is to take
account of the timing of actual cash flows -- especially debt service -- and to put these
cash flows into the broader context of the utility's overall finances. One reason for doing
this is to see if the timing of costs and benefits requires changes in rates in order to
cover expenses. In particular, there are three ways that conventional debt financing and
ratemaking can lead to initial rate increases when a capital -intensive project such as
hydro is put on line. These problems are listed in order of increasing importance for
rates:
Problem 1: Conventional debt usually requires constant nominal dollar payments to
repay debt. Such payments are declining when expressed in real dollars, which means
that the real capital cost payments are front -loaded onto the early years.
Rural Hydro Phase 2 Economic Evaluation 114198 page 9
I Problem 2: In addition to the front -loading caused by constant nominal debt service,
conventional utility ratemaking usually calculates revenue requirements using
depreciation plus interest. Since first -year depreciation greatly exceeds the first -year
component of debt service that represents principal, this ratemaking practice leads to a
further potential for front -loading of costs onto rates.
Problem 3: Lenders (or political regulators) may require that expected utility revenues
be sufficient to provide a "cushion" of positive net earnings that allows for some volatility
in actual revenues without jeopardizing the ability to make interest payments. Typically
this is expressed as a required ratio of:
TIER= Times Interest Earned Ratio = (Net Income + Interest)/Interest
WFor example, the minimum required TIER imposed by the federal government on
borrowers from the Rural Utilities Service is 1.5. Golden Valley Electric Association is a
regulated cooperative and has an approved target TIER of about 1.8. Unlaska is an
unregulated municipal, but might be subject to a TIER requirement as part of a debt
covenant.
Scope of the Financial Analysis. The issues above must be addressed on a utility -
wide basis. The financial analysis model is therefore designed to capture the following
broad phenomena which apply to the City of Unalaska electric system:
• Some costs are relatively fixed, so that ongoing load growth tends to keep rates
down.
• The hydro project is a relatively small piece of the total system in terms of output,
although it would be a significant part of the asset base. It is important to consider
this relationship to the total system because the other costs (distribution, admin,
etc.) act as a sort of financial ballast on rates even when production costs are
changing rapidly.
• A significant portion of current plant in Unalaska has been grant -financed, but this is
not expected to continue. So future depreciation and interest to maintain current
levels of plant will be higher. This puts some "background" upward pressure on rates
with or without hydro.
• Customer class structure is assumed constant, so that growth in loads translates
directly into revenue growth at existing rates.
Determination of Revenue Requirements. The analysis determines annual revenue
requirements for the entire electric system with and without the hydro project. The cost
of service for a nonprofit utility is typically computed in one of two different ways. The
accrual basis calculation uses financial accounting costs, including depreciation, while
the cash -basis calculation uses debt principal in lieu of depreciation. To the cost of
service is added the requirement for a cushion of net income, or "margin" sufficient to
provide for the target TIER:
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 10
Accrual Basis Cash Basis
Fuel Fuel
+ Other Operating Other Operating
+ Depreciation Debt Prinipal Payments
+ Interest Interest
Cost of Service Cost of Service
+ Margins Margins
= Revenue Requirement Revenue Requirement
Specific Financial Assumptions. The following specific assumptions, repeated from
Table 1 above, are used:
Financial Parameters
,Nominal e t Interest Rate !: a
o;
New Debt Issuance Cost ; a of fac—evalu
2.0%i
Inflation Rate I o
3.0%,
arget TIER Ratio
1,5,
PlantAdditions: Book I-Ife
o e t o u!
j ew eese 151
o I fl.
I ew y ro 1
o o,
1 of er ew ant j
o f o,
The debt issuance cost adds an additional 2 percent to the cost of the hydro project that
is not included in the economic analysis. The average 17-year life of all other electric
plant was determined from analysis of current depreciation expense relative to plant
amounts. The debt repayment term is the same as the book life for each type of plant.
Constant nominal payments of (principal + interest] are assumed.
In addition to these parameters, I use the following key assumptions to project future
expenses:
• The economic model already projects diesel generator and hydroelectric plant in
service. To project all other plant, I assume that this other net plant in service grows
with load. On a nominal -dollar basis, required net plant also grows with inflation.
• Admin & General costs are fixed in real dollars. They grow in nominal dollars with
inflation. Distribution O&M is also fixed in real dollars. This assumption is harder to
justify but it was used in Unalaska's most recent rate study.
• Production nonfuel operating costs (mostly labor and overhauls) are partly fixed.
They grow in real terms at half the rate of load growth.
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 11
3.2. Pyramid #4 Financial Analysis: Results
Revenue Requirements without Hydro. Table 8 shows the projected cost of service
for the system without hydra The main forces acting on all costs are 3% inflation and
2% load growth.
Table 8:
Accrual Basis Cost of Service Without Hydro for mid -range assumptions
(nominal rinlinm rtaca mmmmml
a •.-
.: ..� �.
In addition to the direct cost of service, revenue requirements must also meet the target
TIER ratio of 1.5. That means that margins must equal 50% of interest expense. The
margins accrue to the utility, so they are like a forced equity contribution from
customers. They can be used to fund future capital expenditures or to otherwise keep
future rates down. Figure 2 shows projected revenue requirements under accrual
accounting without hydro. The figure clearly shows how a diesel -based utility has
relatively low capital costs and relatively high operating costs.
Figure 2:
Revenue Requirements, No Hydro, midrange assumptions
Revenue Reqts —No Hydro i
30,000,000
25,000,000
20,000,000
15,000,000
10,000,000
i
5,000,000
FJ
rn o d O a N W) CO r v f+ O M M
a� o 0 a 0 0 0 0 0 0 o a CD0
N N N N N N N N N N N N N
Interest j
Deprec
i
i
I
i
r Margin � I
Interest
Deprec 1`
❑OthrOp
p Fuel
Rural Hydro Phase 2 Economic Evaluation 114198 page 12
Revenue Requirements with Hydro. Table 9 and Figure 3 show the same projections
for the system with the Pyramid #4 hydro project included. Close inspection of the
figures or tables shows that the cost of service and revenue requirements are generally
lower with hydro after about the year 2005, as we would expect given the positive net
economic benefits of hydro. The main point of these presentations, however, is to show
that the hydro project has a very small effect on the evolution of total system costs.
Table 9:
Cost of Service with Hvdra_ mirirnnria ncciimr+;nnc (r7cn .,,�_x
_., ..
•• 11 11 1 1 1 1
1 1
• r. •�. .. ; ..
• �:
•
• ••TUNWIgrAMMgJAIMMU
• •• 1•• ••• ..� ..
.� ..•
RM
-
1 1•• •. •
Figure 3:
Revenue Requirements with Hydro, midrange assumptions
Revenue Reqts —With Hydro
30,000,000
25,000,000
20,000,000
15,000,000
10,000,000
5,000,000
ti O M c0 M N LO CO Q ti O M M
Q7 O O O O O O O O Q C3 4 O CDN N N N N N [V N N N N N N
Interest
Deprec
IX 9
y Interest
� Deprec
a Oth r Op
p Fuel
Difference in Revenue Requirements due to Hydro. With this context established,
we now consider the difference in revenue requirements due to the hydro project, under
various sets of assumptions. Table 10 summarizes these differences for the midrange
assumptions (case mmmmm).
Rural Hydro Phase 2 Economic Evaluation 114198 page 13
Table 10:
Differences in Revenue Requirements due to Hydro, midrange assumptions
Key increases(Decreases) in Cost ue to y ro
Accrual Basis Cost of Servic 1997 2002 2005 2010 2020 2030
Fuel 0 (164,875) (182,880) (217,361) (307,054) (433,758)
Other Operating 0 (5,840) (6,381) (7,397) (9,941) (13,361)
Depreciation 0 81,704 81,704 81,704 81,704 81,704
Interest 0 148,112 141,709 128,205 85,961 10,281
Total (Accrual] Cost of Se 0 59,101 34,152 (14,849) (149,340) (355,133)
Cash Basis Revenue Requirement
Fuel 0 (164,875) (182,880) (217,361) (307,054) (433,758)
Other Operating 0 (5,840) (6,381) (7,397) (9,941) (13,361)
Debt Principal 0 33,522 39,925 53,429 95,682 171,352
Interest 0 148,112 141,709 128,205 85,951 10,281
Required Margin for TIER 1. 0 74,056 70,854 64,103 42,976 5,141
Total [Cash] Revenue Req 0 84,975 63,227 20,978 (92,386) (260,345)
The economic analysis above showed that in this case the hydro project has net
economic benefits of $1.1 million in present value. However, this table shows that the
annual cost of service is higher with hydro until at least 2005. The actual "crossover
years" during which with -hydro cost of service falls below without -hydro cost for case
(mmmmm) are as follows:
Accounting Basis Cost of Service Revenue Re 'ts
Accrual basis2009 2014
Cash basis 2004
2013
Figure 4 summarizes what is going on. It shows the difference in the cost of service (as
bars) and the main components of that difference (as lines). There is a spike in year
2001 as the interest on the hydra outlay kicks in. In 2002, depreciation jumps and fuel
prices drop as the hydro plant is placed in service. During the first 7 years of operation,
the interest plus depreciation on the hydro project exceed the operating savings, which
are almost entirely fuel. Throughout the project life interest declines and depreciation
stays constant, while fuel savings increase with inflation and (in this case) 0.5% real
growth in prices. (Fuel savings do not of course increase with load).
Rural Hydro Phase 2 Economic Evaluation 114/98 page 14
Figure 4: Effect of hydro on cost of service, case mmmmm
Differences in Cost of Service due to Hydro
(Utility Basis Acounting, Margins Excluded)
200 000
100,000
0
(100,000)
o (200,000)
(300,000)
(400,000)
(500,000)
! (600,000)
! t- O M to M N LO co O cl M
m Q O O 0 r N N CV M M n
c, 0 0 0 0 0 0 0 0 0 0 0 0 0
- CV N N N N N N N N N N N N
3
year
+_ Fuel
Other Op
—� Deprec
The relative increase in early costs, however, are small, as shown in Table 11. For
example, using the cash basis of accounting, which is what some lenders would
probably do, the initial difference in revenue requirements is only 1.5%.
Table '11
is Change in Lost ana revenue Keq•ts aue to rlyaro, case mmmmm
/o cnarrges due to Hydro
-
Accrual Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
1.1%
0.5%
-0.2%
-1.1%
-1.6%
Change in Revenue Req'ts
0.0%
2.3%
1.6%
0.5%
-0.7%
-1.6%
Cash Basis
Change in Cost of Service
0.0%
0.2%
-0.1 %
-0.5%
-1.0%
-1.2%
Change in Revenue Req'ts
0.0%
1.5%
0.9%
0.2%
-0,6%
-1.1%
Difference from Existing Rates. In FY97, the Unalaska Electric Enterprise Fund ran a
surplus of about $360,000, or 7% of revenue. (This number corresponds to the "margin"
in this analysis). If this surplus could be maintained, it would more than cover any
required increases in revenue requirements due to hydra debt. However, the budgeted
surpluses for FY97 and FY98 are essentially zero. If lenders expect the budgeted
surplus of zero to occur, they might push for slight changes in rates to meet a target
level of margins.
Results for Other Sets of Assumptions. Table 12 shows the difference in cost of
service for all six combinations of construction cost and fuel price escalation. The main
conclusion to note is that with the low (force account basis) construction cost, the cost
Rural Hydro Phase 2 Economic Evaluation 114198 page 15
1
of service drops immediately under all fuel price scenarios, because the first year fuel
savings exceed the first year sum of hydro depreciation plus interest.
Table 12: Summary of Accrual Racic r'.nct of Saniirrn _F uva.._
Pyramid Financial Results
ummary:
Increase (Decrease)
in Accrual Basis Cost of Service due to Hydro
(based on depreciation plus interest and excludes margins)
Current Dollars
% Change from Diesel -only
2002 2005
2010
2020
2030
2002 2005 2010 2020 2030
Contractor cost
Fuel growth: low
63:162
41.306 (1.203) (116.062)
(289,307)
1.1% 0.6010
0.0%
-09%
0.o%
mid
59.101
34,152 (14,849) (149.340)
(355,133)
1.1% 0.5%
-0.2%
-1.1%
D.09'o
high
50.734
19.078 (44.707) (22--1.866)
(522.752)
0.9% 0.3°6
-0.5%
-1.5%
0.0%
Force account cost
Fuel growth: low
(2.254)
(22,288) (60.953) (163.784)
(315,490)
0.0% -0.3%
-0.7%
-1.2%
0.0%
mid
(6.315)
(29,441) (74,599) (197.062)
(381,316)
-0.1% -0.5916
-0.9%
-1.4%
0.0%
high
(14.682)
(44,316) (104.456) (275.588)
(548,935)
-0.3% -0.7% -1.2%
-1.8%
0.0%
Table 13 shows the same summary but uses the cash basis revenue requirements as
the measure of cost. This table shows the changes in revenue requirements due to
hydro under a ratemaking procedure that requires revenue to cover debt principal
payments, interest, plus 50% of interest as a margin. (So that (i nterest+ma rg in)/i nte rest
= 1.5 = target TIER). The higher interest expense from hydro is amplified by the
requirement to provide for a margin and as a result revenue requirements with hydro
are higher until about 2010.
Table 13: Summary of Cash Basis RP_vP_nt]a Ranitiramnnt Imnmrfc ^f {-wAr„
Pyramid Financial Results
ummary:
-
Increase
(Decrease) in Cash -Basis Revenue Requirements due to Hydro
(based on on debt principal payments plus interest and includes margins)
Current Dollars
%CChange from Diesel-only-
2002 2005 2010
2020
2030
2002 2005 2010 2020 2030
Contractor cost
Fuel growth: low
89,035
70,380 34,624 (59,108)
(194,518)
1.6% 1.1% 0.4%
-0.4%
-0.9%
mid
84,975
63,227 20,978 (92,386)
(260,345)
1.5% 0.9% 0.2%
-0.6%
-1.1%
high
76,607
48,152 (8,880) (170,912)
(427,964)
1.3% 0.7% -0.1%
-1.1%
-1.6%
Force account cost
Fuel growth: low
16,255
(1,489) (35,324) (123,042)
(247,683)
0.3% 0.0% -0.4%
-0.9%
-1.2%
mid
12,194
(8,642) (48,970) (156,320)
(313,509)
0.2% -0.1% -0.6%
-1.1%
-1.4%
high
3,826
(23,717) (78,828) (234,846)
(481,128)
0.1% -0.3% -0.9%
-1.5%
-1.8%
Discussion of Results. The financial analysis shows that some very minor increases
as measured by cost of service occur with contractor construction cost but not with
force account construction cost. if a TIER requirement of 1.5 is imposed and some
margins must be recovered in revenue, then the hydro project causes initial increases
in revenue requirements for the first 5-10 years even with low construction cost.
Collected margins accrue to the benefit of the utility, which as a municipal entity is
Rural Hydra Phase 2 Economic Evaluation
1/4/98 page 16
controlled by its ratepayers. In any event, the pyramid ##4 hydra project would be a
relatively small piece of the overall utility system, especially as time passes and load
grows. Its effects en system costs and revenue requirements in the early years are
quite modest in all cases. The maximum first year impact reported above, under the
most pessimistic assumptions, is only 1.6%.
In summary, the Pyramid #4 project has very minor financial impacts because it plays a
modest role in overall utility operations. This overall conclusion is clearly shown in
Figure 5, which shows the average cost of service with and without the hydro project
under midrange assumptions.
Figure 5
Average Cost of service without and With Hydro
(Accrual Basis, excludes margins)
500
45.0
40.0
f
35.0
30.0
i 25.0
Ln
20.0
m
15.0
10.0
I
i 5.0
0.0
j O O O O N r -r N N N M M to
M
O O O O O O O O O O 0 0 O
N N N N N N N N N N N N N
3.3. Financial Analysis of Combined Alternatives 4 plus 1
w Rhout hydro
.. _ .. w b hydra
The addition of the alternative #1 power recovery project has little effect on the cost of
service. The initial increase (year 2002) in cost of service goes up by about one half of
one percentage point when alternative #1 is included with #4. Table 14 summarizes the
effects of the combined projects under midrange assumptions and the appendix
provides more details, including a summary for force account construction costs.
Rural Hydro Phase 2 Economic Evaluation 114198 page 17
l
f
1
Table 14: Financial Impacts Summary for Combined Alternatives #1 and #4
case mmmmm (contractor cost, 0.5% real fuel price growth)
trey increases (Decreases) in Gost
Uue to
Hydro
Accrual Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(185.348)
(205,588)
(244,352)
(345,182)
(487,619)
Other Operating
0
(6,565)
(7,173)
(8,316)
(11,176)
(15,020)
Depreciation
0
100,801
100,801
100,801
100,801
100,801
Interest
0
182,729
174,829
158,169
106,040
12,684
Total [Accrual] Cost of Servi
0
91,616
62,868
6,303
(149,517)
(389,154)
Cash Basis Revenue Requirement
Fuel
0
(185,348)
(205,588)
(244,352)
(345,182)
(487,619)
Other Operating
0
(6,565)
(7,173)
(8,316)
(11,176)
(15,020)
Debt Principal
0
41,356
49,256
65,916
118,045
211,401
Interest
0
182,729
174,829
158,169
106,040
12,684
Required Margin for TIER 1.5
0
91,364
87,415
79,085
53,020
6,342
Total [Cash] Revenue Req't
0
123,537
98,738
50,503
(79,252)
(272,211)
o Changes -due to Hydro
Accrual Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
1.6%
1.0%
0.1%
-1.1%
-1.8%
Change in Revenue Req'ts
0.0%
3.2%
2.2%
0.9%
-0.7%
-1.7%
Cash Basis
Change in Cast of Service
0.0%
0.6%
02%
-0.3%
-1.0%
-1.3%
Change in Revenue Req'ts
0.0%
22%
1.5%
0.6%
-0.5%
-1.2%
Rural Hydro Phase 2 Economic Evaluation
114198 page 18
Appendix:
Financial Analysis Summaries
This appendix contains summaries of the cost of service and revenue requirements,
for the following cases:
Project
Hydro Cost
Fuel Price Growth
case name
Pyramid #4
high
low
mim.mm
Pyramid #4
high
mid
mmmmm (midrange or "base")
Pyramid #4
high
high
mhmmm
Pyramid #4
low
low
mlmlm
Pyramid #4
low
mid
mlmlm
Pyramid #4
low
high
mhmlm
Pyramid [#4 + #11 high mid
Pyramid [#4 + #11 low mid
Rural Hydro Phase 2 Economic Evaluation
mmmmm
mmmlm
I
1/4/98 page 19
Financial Analysis Summary for case mimmm
+te: yrami
Load growth= 2.0% mid
real fuel price growth= 0.0% low
hydro capital cost= 2,177.800 contractor
Cost Q @NIce
Without Hydro
1997
2002
2005
2010
2020
2030
Fuel
1,583,247
2,026,449
2,349,892
3,007,702
4,927,297
8,072,029
Other Operating
2,327,119
2,768,331
3,073,350
3,660,394
5,204,055
7,421,351
Depreciation
342,417
484,076
539,793
1,020,285
1,748,263
2,569,244
Interest
Total Cost of Service
30,742
4,283,525
276,984
5,555,840
422,484
61385,518
750,619
8,439,000
1,261,366
13,140,981
2,031,194
Avg cents/kWh
16.0
18.8
20.4
24.4
20,093,819
31.1
39.0
With Hydro
Fuel
1,583,247
1,865,634
2,174,165
2,803,987
4,653,521
7,704,097
Other Operating
2,327,119
2,762,492
3,066,969
3,652,996
5,194,114
7,407,991
Depreciation
342,417
565,780
621,498
1,101,990
1,829,967
2,650,948
Interest
'total Cost of Service
30,742
4,283,525
425,096
5,619,002
564,192
6,426,824
878,824
8,437,797
1,347,317
13,024,919
2,041,475
13,804,512
Avg cents/kWh
16.0
19.0
20.5
24.4
30.8
38.5
nra,au= uac uruparisan
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Without Hydro
16.0
18.8
20.4
24.4
31.1
39,0
With Hydro
16.0
19.0
20.5
24.4
30.8
38.5
DifferencC
0.0
0.2
0.1
(0.0)
(0.3)
(0.6)
Cash Basis Revenue Requirements
Without Hydro
15.5
18.9
21.0
24.8
33.0
41.3
With Hydro
15.5
19.2
21.2
24.9
32.9
40.9
Difference
0.0
0.3
0.2
0.1
(0.1)
(0.4)
Key ncreases ecreases in Gost Due
to
Wydro
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(160,815)
(175.726)
(203,715)
(273,776)
(367,932)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Depreciation
0
81,704
81,704
81,704
81,704
81,704
Interest
0
148,112
141,709
128,205
85,951
10,281
Total [Utility] Cost of Service
0
63,162
41,306
(1,203)
(116,062)
(289,307)
Cash Basis Revenue Requirement
Fuel
0
(160,815)
(175,726)
(203,715)
(273,776)
(367,932)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Debt Principal
0
33,522
39,925
53,429
95,682
171,352
Interest
0
148,112
141,709
128,205
85,951
10,281
Required Margin for TIER 1.5
0
74,056
70,854
64,103
42,976
5,141
Total [Cash] Revenue Req't
0
89,035
70,380
34,624
(59,108)
(194,518)
.n %,11a►►yes Uu0 co ►7yaro
Utility Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
1.1%
0.6%
0.0%
-0.9%
-1.4%
Change in Revenue Req'ts
0.0%
2.4%
1.7%
0.7%
-0.5%
Cash Basis
Change in Cost of Service
0.0%
0.3%
0.0%
-0.4%
-0.8%
Change in Revenue Reg1s;
0.0%
1.6%
1.1 %
0.4%
-0.4%
-0.9%
source., pyramid2.xls sheet net ben
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 20
Financial Analysis Summary for case mmmmm
Site: Pyramid
Load growth= 2.0% mid
real fuel price growth= 0.5% mid
hydro capital cost= 2.177,800 contractor
Cost of Service
Without Hydro
1997
2002
2005
2010
2020
2030
Fuel
1,583,247
2,077,619
2,445,549
3,209,177
5,526,220
9,516,183
Other Operating
2,327,119
2,768,331
3,073,350
3,660,394
5,204,055
7,421,351
Depreciation
342,417
484,076
539,793
1,020,285
1,748,263
2,569,244
Interest
30,742
276,984
422,484
750,619
1,261,366
2,031,194
Total Cost of Service
4,233,525
5,607,010
6,481,175
8,640,474
13,739,904
21,537,972
Avg cents/kWh
16.0
19.0
20.7
24.9
32.5
41.8
With Hydro
Fuel
1,583,247
1,912,744
2,262.669
2,991,815
5,219,166
9,082,424
Other Operating
2,327,119
2,762,492
3,066,969
3,652,996
5,194,114
7,407,991
Depreciation
342,417
565,780
621,498
1,101,990
1,829,967
2,650,948
Interest
30,742
425,096
564,192
878,824
1,347,317
2,041,475
Total Cost of Service
4,283,525
5,666,112
6,515,328
8,625,625
13,590,564
21,182,839
Avg cents/kWh
16.0
19.2
20.8
24.9
32.2
41.2
Average Gost Comparison
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Without Hydro
16.0
19.0
20.7
24.9
32,5
41.8
With Hydro
16.0
192
20.8
24.9
32.2
41.2
Difference
0.0
0.2
0.1
(0.0)
(0.4)
(0.7)
Cash Basis Revenue Requirements
Without Hydro
15.5
19.0
21.3
25.4
34.4
44.1
With Hydra
15.5
19.3
21.5
25,5
34.2
43.6
Difference
0.0
0.3
0.2
0.1
(0.2)
(0.5)
ey Increases?Decreases) in Cost Due
to
Hydro
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(164,875)
(182,880)
(217,361)
(307,054)
(433,758)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Depreciation
0
81,704
81,704
81,704
81,704
81,704
Interest
0
148,112
141,709
128,205
85,951
10,281
Total [Utility] Cost of Service
0
59,101
34,152
(14,849)
(149,340)
(355,133)
Cash Basis Revenue Requirement
Fuel
0
(164,875)
(182,880)
(217,361)
(307,054)
(433,758)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Debt Principal
0
33,522
39,925
53,429
95,682
171,352
Interest
0
148,112
141,709
128,205
85,951
10,281
Required Margin for TIER 1.5
0
74,056
70,854
64,103
42,976
5,141
Total [Cash] Revenue Req't
0
84,975
63,227
20,978
(92,386)
(260,345)
Utility Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
1.1%
0.5%
-0.2%
-1.1%
-1.6%
Change in Revenue Req'ts
0.0%
2.3%
1.6%
0.5%
-0.7%
-1.6%
Cash Basis
Change in Cost of Service
0.0%
0.2%
-0.1 %
-0.5%
-1.0%
-1.2%
Change in Revenue Req'ts
0.0%
1.5%
0.9%
0.2%
-0.6%
-1.1%
source: pyramid2.xls sheet net ben
Rural Hydro Phase 2 Economic Evaluation 114/98 page 21
Financial Analysis Summary for case mhmmm
Site: Pyramid
Load growth= 2.0% mid
real fuel price growth= 1.5% high
hydro capital cost= 2,177,800 contractor
Cost of Service
Without Hydro
1997
2002
2005
2010
2020
2030
Fuel
1,583,247
2,183,061
2,647,135
3,650,004
6,939,493
13,193,564
Other Operating
2,327,119
2,768,331
3,073,350
3,660,394
5,204,055
7,421,351
Depreciation
342,417
484,076
539,793
1,020,285
1,748,263
2,569.244
Interest
30,742
276,984
422,484
750.619
1.261,366
2,031,194
Total Cost of Service
4,283,525
5,712,452
6,682,762
9,081,302
15,153,176
25,215.353
Avg cents/kWh
16.0
19.3
21.3
26.2
35.9
49.0
With Hydro
Fuel
1,583,247
2,009,818
2,449,181
3,402,785
6,553,913
12,592,187
Other Operating
2,327,119
2,762,492
3,066,969
3,652,996
5,194,114
7,407,991
Depreciation
342.417
565,780
621,498
1,101,990
1,829,967
2,650.948
Interest
30,742
425,096
564,192
878,824
1,347,317
2,041.475
Total Cost of Service
4,283,525
5,763,186
6,701,840
9,036,595
14,925,311
24,692.601
Avg cents/kWh
16.0
19.5
21.4
26.1
35.3
48.0
,average Lost (;omparrson
--
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Without Hydro
16.0
19.3
21.3
26.2
35.9
49.0
With Hydro
16.0
19.5
21.4
26.1
35.3
48.0
Difference
0.0
0.2
0.1
(0.1)
(0.5)
(1.0)
Cash Basis Revenue Requirements
Without Hydro
15.5
19.4
21.9
26.7
37.8
51.2
With Hydro
15.5
19.7
22.1
26.7
37.4
50.4
Difference
0.0
0.3
0.2
(0.0)
(0.4)
(0.8)
ney increases (uecreases) 1n Gast
Due to
hydro
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(173,243)
(197,954)
(247,219)
(385,580)
(601,377)
Other Operating
0
(6,840)
(6,381)
(7,397)
(9,941)
(13,361)
Depreciation
0
81,704
81,704
81,704
81,704
81.704
Interest
0
148,112
141,709
128,205
85,951
10,281
Total [Utility] Cost of Service
0
50,734
19,078
(44,707)
(227,866)
(522,752)
Cash Basis Revenue Requirement
Fuel
0
(173,243)
(197,954)
(247,219)
(385,580)
(601,377)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Debt Principal
0
33,522
39,925
53.429
95,682
171,352
Interest
0
148,112
141,709
128,205
85,951
10,281
Required Margin for TIER 1.5
0
74,056
70,854
64,103
42,976
5,141
Total [Cash] Revenue Req't
0
76,607
48,152
(8,880)
(170,912)
(427,364)
Utility Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
0.9%
0.3%
-0.5%
-1.5%
-2.1%
Change in Revenue Req'ts
0.0%
2.1%
1.3%
0.2%
-1.2%
-2.0%
Cash Basis
Change in Cost of Service
0.0%
0.0%
-0.3%
-0.8%
-1.4%
-1.7%
Change in Revenue Req'ts
0.0%
1.3%
0.7%
-0.1%
-1.1%
-1.6%
source: pyramid2.xls sheet net ben
Rural Hydro Phase 2 Economic Evaluation 1/4198 page 22
1
Financial Analysis Summary for case mlmlm
I
Site: Pyramid
Load growth= 2.0% mid
real fuel price growth= 0.0% low
hydro capital cost= 1,557,900 force
Cost of Service
Without Hydro
1997
2002
2005
2010
2020
2030
Fuel
1.583,247
2,026,449
2,349,892
3,007,702
4.927,297
8,072.029
Other Operating
2,327,119
2,768,331
3,073,350
3,660,394
5,204,055
7,421.351
Depreciation
342,417
484,076
539,793
1,020,285
1,748,263
2.569.244
Interest
30,742
276,984
422,484
750,619
1,261,366
2.031.194
Total Cost of Service
4,283,525
5,555,840
6,385,518
8,439,000
13,140,981
20,093,819
Avg cents/kWh
16.0
18.8
20.4
24.4
31.1
39.0
With Hydro
Fuel
1,583,247
1,865,634
2,174,165
2,803,987
4,653,521
7,704.097
Other Operating
2.327,119
2,762,492
3,066,969
3,652,996
5,194,114
7,407,991
Depreciation
342,417
542,523
598,241
1,078,733
1.806,710
2,627,691
Interest
30,742
382,937
523,856
842,331
1,322,851
2,038,549
Total Cost of Service
4,283,525
5,553,586
6,363,230
8,378,047
12,977,196
19,778,328
Avg cents/kWh
16.0
18.8
20.3
24.2
30.7
38.4
Average t.osr t,ompanson
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Without Hydro
16.0
18.8
20.4
24.4
31.1
39.0
With Hydro
16.0
18.3
20.3
24.2
30.7
38.4
Difference
0.0
(0.0)
(0.1)
(0.2)
(0.4)
(0.6)
Cash Basis Revenue Requirements
Without Hydro
15.5
18.9
21.0
24.8
33.0
41.3
With Hydro
15.5
18.9
21.0
24.7
32.7
40.8
Difference
0.0
0.1
(0.0)
(0.1}
(0.3)
ey Increases ecreases rn Cost
Due to
Hydro
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(160,815)
(175,726)
(203,716)
(273,776)
(313,361)
Other Operating
0
(5,840
(6,3$1)
(7,397)
(9,941)
(,61)
Depreciation
0
58,448
58,448
58,448
58,448
58,448
Interest
0
105,953
101,372
91,712
61,486
7,355
Total (utility] Cost of Service
0
(2,254)
(22,288)
(60,953)
(163,784)
(315,490)
Cash Basis Revenue Requirement
Fuel
0
(160,815)
(175,726)
(203,715)
(273,776)
(367,932)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Debt Principal
0
23,980
28,560
38,220
68,447
122,578
Interest
0
105,953
101,372
91,712
61,486
7,355
Required Margin for TIER 1.5
0
52,976
50,686
45,856
30,743
3,677
Total (Cash] Revenue Req't
0
16,255
(1,489)
(35,324)
(123,042)
(247,683)
Utility Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
0.0%
-0.3%
-0.7%
-1.2%
-1.6%
Change in Revenue Req'ts
0.0%
0.9%
0.4%
-0.2%
-1.0%
-1.5%
Cash Basis
Change in Cost of Service
0.0%
-0.7%
-0.8%
-1.0%
-1.2%
-1.2%
Change in Revenue Req'ts
0.0%
0.3%
0.0%
-0.4%
-0.9%
-1.2%
source: pyrarnid2.As sheet net ben
Rural Hydro Phase 2 Economic Evaluation 1/4/98 page 23
Financial Analysis Summary for case mmmim
ite: t-wamid #4
Load growth= 2.0% mid
real fuel price growth= 0.-;'o mid
hydro capital cost= 1.557,900 force
Cost of Se-rVice
Without Hydro
1997
2002
2005
2010
2020
2030
Fuel
1,583,247
2.077,619
2,445,549
3,209,177
5,526,220
9,516,183
Other Operating
2,327,119
2,768,331
3,073,350
3,660,394
5,204,055
7,421,351
Depreciation
342,417
484,076
539,793
1,020,285
1,748,263
2,569.244
Interest
30,742
276,984
422,484
750,619
1,261,366
2,031,194
Total Cost of Service
4,283,525
5,607,010
6,481,175
8,640,474
13,739,904
21,537,972
Avg cents/kWh
16.0
19.0
20.7
24.9
32.5
41.8
With Hydro
Fuel
1,583,247
1,912,744
2,262,669
2,991,815
5,219,166
9,082.424
Other Operating
2,327,119
2,762,492
3,066,969
3,652,996
5,194.114
7.407,991
Depreciation
342,417
542,523
598,241
1,078,733
1,806,710
2,627,691
Interest
30,742
382,937
523,856
842,331
1,322,851
2,038,549
Total Cost of Service
4,283,525
5,600,696
6,451,714
8,565,876
13,542,841
21,156,656
Avg cents/kWh
16.0
18.9
20.6
24.7
32,1
41.1
average Gast comparison
Utility Basis Cast of Service
1997
2002
2005
2010
2020
2030�
Without Hydro
16.0
19,0
20.7
24.9
32.5
41.8
With Hydro
16.0
18.9
20.6
24.7
32.1
41.1
Difference
0.0
(0.0)
(0.1)
(0.2)
(0.5)
(0.7)
Gash Basis Revenue Requirements
Without Hydro
15.5
19.0
21.3
25.4
34.4
44.1
With Hydro
15.5
19.1
21.3
25.3
34.1
43.5
Difference
0.0
0.0
(0.0)
(0.1)
(0.4)
(0.6)
ey Increases(Decreases) in Cost Due
to
Hy ro
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(164,875)
(182,880)
(217,361)
(307,054)
(433,758)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Depreciation
0
58,448
58,448
58,448
58,448
58,448
Interest
0
105,953
101,372
91,712
61,486
7,355
Total [Utility] Cost of service
0
(6,315)
(29,441)
(74,599)
(197,062)
(381,316)
Cash Basis Revenue Requirement
Fuel
0
(164,875)
(182,880)
(217,361)
(307,054)
(433,758)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Debt Principal
0
23,980
28,560
38,220
68,447
122,578
Interest
0
105,953
101,372
91,712
61,486
7,355
Required Margin for TIER 1.5
0
52,976
50,686
45,856
30,743
3,677
Total [Cash] Revenue Req't
0
12,194
(8,642)
(48,970)
(156,320)
(313,509)
Utility Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
-0.1%
-0.5%
-0.9%
-1.4%
-1.8%
Change in Revenue Req'ts
0.0%
0.8%
0.3%
-0.3%
-1.2%
-1.7%
Cash Basis
Change in Cost of Service
0.0%
-0.7%
-0.9%
-1.1 %
-1.3%
-1.5%
Change in Revenue Req'ts
0.0%
0.2%
-0.1 %
-0.6%
-1.1 %
-1.4%
source. pyramid2.xls sheet net ben
Rural Hydro Phase 2 Economic Evaluation 1/4198 page 24
Financial Analysis Summary for case mhmlm
Site: Pyrami
Load growth= 2.0% mid
real fuel price growth= 1.5% high
hydro capital cost= 1,557,900 force
Cost of Service,
Without Hydro
1997
2002
2005
2010
2020
2030
Fuei
1,5B3,247
2,183,061
2,647,135
3,650,004
6.939,493
13,193,564
Other Operating
2,327,119
2,768,331
3,073,350
3,660,394
5,204,055
7,421,351
Depreciation
342,417
484,076
539.793
1.020.285
1,748,263
2,569,244
Interest
30,742
276,984
422,484
750,619
1,261,366
2,031,194
Total Cost of Service
4,283,525
5,712,452
6,682,762
9,081,302
15,153,176
25,215,353
Avg cents/kWh
16.0
19.3
21.3
26.2
35.9
49.0
With Hydro
Fuel
1,583,247
2,009,818
2,449,181
3,402,785
6,553,913
12,592,187
Other Operating
2,327,119
2,762,492
3,066,969
3,652.996
5,194,114
7,407,991
Depreciation
342,417
542,523
598,241
1,078,733
1,806,710
2,627,691
Interest
30,742
382,937
523,856
842,331
1,322,851
2,038,549
Total Cost of Service
4,283,525
5,697,770
6,638,246
8,976,845
14,877,588
24,666,418
Avg cents/kWh
16.0
19.3
21.2
25.9
35.2
47.9
Average L.osr t.omparfson
-
Utllity Basis Cost of Service
1997
2002
2005
2010
2020
2030
Without Hydro
16.0
19.3
21.3
26.2
35.9
49.0
With Hydro
16.0
19.3
21.2
25.9
35.2
47.9
Difference
0.0
(0.0)
(0.1)
(0.3)
(0.7)
(1.1)
Cash Basis Revenue Requirements
Without Hydro
15.5
19.4
21.9
26.7
37.8
51.2
With Hydro
15.5
19.4
21.9
26.5
37.2
50.3
Difference
0.0
0.0
(0.1)
(0.2)
(0.6)
(0.9)
Key JnCreaseS(Decreases) in Cost Dueto
Hydro
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(173,243)
(197,954)
(247,219)
(385,580)
(601,377)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Depreciation
0
58,448
58,448
58,448
58,448
58,448
Interest
0
105,953
101,372
91,712
61,486
7,355
Total [Utility] Cost of Service
0
(14,682)
(44,516)
(104,456)
(275,588)
(548,935)
Cash Basis Revenue Requirement
Fuel
0
(173,243)
(197,954)
(247,219)
(385,580)
(601,377)
Other Operating
0
(5,840)
(6,381)
(7,397)
(9,941)
(13,361)
Debt Principal
0
23,980
28,560
38,220
68,447
122,578
Interest
0
105,953
101,372
91,712
61,486
7,355
Required Margin for TIER 1,5
0
52,976
50,686
45,856
30,743
3,677
Total [Cash] Revenue Req't
0
3,826
(23,717)
(73,828)
(234,846)
(481,128)
o Changes due to Hydro
Utility Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
-0.3%
-0.7%
-1.2%
-1.8%
-2.2%
Change in Revenue Req'ts
0.0%
0.7%
0.1%
-0.6%
-1.6%
-2.1%
Cash Basis
Change in Cost of Service
0.0%
-0.9%
-1.1 %
-1.4%
-1.7%
-1.9%
Change in Revenue Req'ts
0.0%
0.1%
-0.3%
-0.9%
-1.5%
-1.8%
source: pyramicIZAs sheet net ben
Rural Hydro Phase 2 Economic Evaluation 1/4198 page 25
Financial Analysis Summary for case mmmmm
7
I
r'yramid ; 4 plus ;;1
Load growth= 2.0% mid
real fuel price growth= 0.5% mid
hydra capital cos;= 2,686,800 contractor
Cost of Service
Without Hydro
1997
2002
2005
2010
2020
2030
Fuel
1,583,247
2,077,619
2,445,549
3,209,177
5,526,220
9,516,183
Other Operating
2,327,119
2,768,331
3.073,350
3,660,394
5,204,055
7,421,351
Depreciation
342,417
484,076
539,793
1,020,285
1,748,263
2,569.244
Interest
30,742
276,984
422,484
750,619
1,261,366
2,031,194
Total Cost of Service
4,283,525
5,607,010
6,481,175
8,640,474
13,739,904
21,537,972
Avg cents/kWh
16.0
19.0
20.7
24.9
32.5
41.8
With Hydra
Fuel
1.583,247
1,892,271
2,239,960
2,964,825
5,181,038
9,028,563
Other Operating
2,327,119
2,761,767
3,066,176
3,652,078
5,192,879
7,406,332
Depreciation
342,417
584,876
640,594
1,121,086
1,849,063
2,670,044
Interest
30,742
459,713
597,313
908,789
1,367,406
2,043,878
Total Cost of Service
4,283,525
5,698,627
6,544,043
8,646,777
13,590,386
21,148,818
Avg cents/kWh
16.0
19.3
20.9
25.0
32.2
41.1
Average Cost Comparison cent
)
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Without Hydro
16.0
19.0
20.7
24.9
32.5
41.8
With Hydro
1e.0
19.3
20.9
25.0
32.2
41.1
Differericd'
0.0
0.3
0.2
0.0
(0.4)
(0.8)
Cash Basis Revenue Requirements
Without Hydro
15.5
19.0
21.3
25.4
34.4
44.1
With Hydro
15.5
19.5
21.6
25.6
34.3
43.5
Difference
0.0
0.4
0.3
0.1
(0.2)
(0.5)
ey increases(Decreases) in Cost
Due to
Hydro
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(185,348)
(205,588)
(244,352)
(345,182)
(487,619)
Other Operating
0
(6,565)
(7,173)
(8,316)
(11,176)
(15,020)
Depreciation
0
100,801
100,801
100,801
100,801
100,801
Interest
0
182,729
174,829
158,169
106,040
12,684
Total [Utility] Cost of Service
0
91,616
62,868
6,303
(149,517)
(389,154)
Cash Basis Revenue Requirement
Fuel
0
(185,348)
(205,588)
(244,352)
(345,182)
(487,619)
Other Operating
0
(6,565)
(7,173)
(8,316)
(11,176)
(15,020)
Debt Principal
0
41,356
49,256
65,916
118,045
211,401
Interest
0
182,729
174,829
158,159
106,040
12,684
Required Margin for TIER 1.5
0
91,364
87,415
79,085
53,020
6,342
Total [Cash] Revenue Req't
0
123,537
98,738
50,503
(79,252)
(272,211)
o Changes due to Trydro
Utility Basis
1997
2002
2005
2010
2020
2030
Change in Cost of Service
0.0%
1.6%
1.0%
0.1 %
-1.1 %
-1 8%
Change in Revenue Req'ts
0.0%
3.2%
2.2%
0.9%
-0.7%
-1.7%
Cash Basis
Change in Cost of Service
0.0%
0.6%
0.2%
-0.3%
-1.0%
-1.3%
Change in Revenue Req'ts
0.0%
2.2%
1.5%
0.6%
-0.5%
-1.2%
Rural Hydro Phase 2 Economic Evaluation 114198 page 26
Financial Analysis Summary for case mmmlm
Cost of Service
Without Hydra
Fuet
Other Operating
Depreciation
Interest
Total Cost of Service
Avg cents/kW h
With Hydro
Fuel
Other Operating
Depreciation
Interest
Total Cost of Service
Avg cents/kWh
Site: PyramTa *4 pus m3
Load growth= 2.0% mid
real fuel price growth= 0.5% mid
hydro capital cost= 1,950,400 force
1997
2002
2005
2010
2020
2030
1,583,247
2,077,619
2.445.549
3,209,177
5,526,220
9.516,183
2,327,119
2,768,331
3.073,350
3,660,394
5,204,055
7,421,351
342,417
484,076
539,793
1,020,285
1.748,263
2.569,244
30,742
276,984
422A84
. 750,619
1,261,366
2,031,194
4,283,525
5,607,010
6,481,175
8,640,474
13,739,904
21,537,972
16.0
19.0
20.7
24.9
32.5
41.8
1,583,247
1,892,271
2.239,960
2,964,825
5,181,038
9,028,563
2,327,119
2,761.767
3:066,176
3,652,078
5,192,879
7,406,332
342,417
557,249
612,966
1,093,458
1,821,436
2,642,417
30,742
409,631
549,396
865,437
1,338,342
2,040,402
4,233,525
5,620,917
6,468,498
8,575,798
13,533,695
21,117,714
16.0
19.0
20.6
24.8
32.1
41.0
,., -,V- ..wiffli.,aidQVII tLt:jrc�nvrrJ!
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Without Hydro
16.0
19.0
20.7
24.9
32.5
41.8
With Hydro
16.0
19.0
20.6
24.8
32.1
41.0
Difference
0.0
0.0
(0.0)
(0.2)
(0,5)
(0.8)
Cash Basis Revenue Requirements
Without Hydro
15.5
19.0
21.3
25.4
34,4
44.1
With Hydra
15.5
19.2
21.3
25.3
34.1
43.4
Difference
0.0
0.1
0.0
(0.1)
(0.4)
(0.7)
ey Increases(Decreases) in Cost Due
to
Hydro
Utility Basis Cost of Service
1997
2002
2005
2010
2020
2030
Fuel
0
(185,348)
(205,588)
(244,352)
(345,182)
(487,619)
Other Operating
0
(6,565)
(7,173)
(8,316)
(11,176)
(15,020)
Depreciation
0
73,173
73,173
73173
73,173
73,173
Interest
0
132,646
125,912
114,818
76,976
9,208
Total [Utility] Cost of Service
0
13,906
(12,677)
(64,676)
(206,203)
(420,258).
Cash Basis Revenue Requirement
Fuel
0
(185,348)
(205,588)
(244,352)
(345,182)
(487,619)1:
Other Operating
0
(6,565)
(7,173)
(8,316)
(11,176)
(15,020)j
Debt Principal
0
30,021
35,756
47,850
85,691
153,460
Interest
0
132,646
126,912
114,818
76,976
9,2081
Required Margin for TIER 1.5
0
66,323
83,456
57,409
38,488
4,504
Total [Cash] Revenue Req't
0
37,078
13,362
(32,590)
(155,202)
(335,367'
.- .,.. .�..-........v r jy..ri v
Utility Basis
1997
2002
2005
2010
Change in Cost of Service
0.0%
0.2%
-0.2%
-0 7%
Change in Revenue Req'ts
0.0%
1.4%
0.8%
-0.1%
Cash Basis
Change in Cost of Service
0.0%
-0.5%
-0.8%
-1.1%
Change in Revenue Req'ts
0.0%
0.7%
0.2%
-0.4%
source: pyrmid2b.)ls sheet net ben
Rural Hydra Phase 2 Economic Evaluation 1/4/98 1
WzWx@1
ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS
RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY
PHASE II
8. APPENDICES
APPENDIX A: ENERGY MODEL OUTPUT
1. Old Harbor
2. Unalaska
APPENDIX B: COST ESTIMATES
1. Old Harbor
2. Unalaska
APPENDIX C: REPORTS ON ECONOMIC AND FINANCIAL ANALYSES
1. Old Harbor
2. Unalaska
LOCHER INTERESTS, LTD. PAGE 8.1 JANUARY 09, 1998