HomeMy WebLinkAboutFalls Creek (Gustavus) Hydroelectric Project Economic Analysis - Nov 2003 - REF Grant 2195387ECONOMIC ANALYSIS OF THE PROPOSED
GUSTAVUS ELECTRIC
FALLS CREEK HYDRO PROJECT
AND POTENTIAL ALTERNATIVES
______________________________________________________________________________
Eric Cutter
David Deputy
November 5, 2003
Prepared for
The Sierra Club
100th Meridian
Water and Energy Resource Management
28 Durham Rd.
San Anslemo, CA 94960
(415) 847-3365
ericcutter@100thMeridian.net
www.100thMeridian.net
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CONTENTS
I. Executive Summary .................................................................................................................. 2
II. Falls Creek Project Economics ................................................................................................. 5
A. Applicable Legislation ........................................................................................................ 5
B. Gustavus Electric Demand and Load Growth ..................................................................... 7
C. Falls Creek Construction and Operating Costs ................................................................. 11
D. Financing and Rate Calculations ....................................................................................... 13
E. Falls Creek Hydro Project Firm Capacity ......................................................................... 15
F. Gustavus Electric Rates ..................................................................................................... 16
III. Promising Alternative Sources of Electric Generation ........................................................... 20
A. Tidal .................................................................................................................................. 20
1. Tidal Energy Costs ......................................................................................................... 20
2. Tidal Technologies ......................................................................................................... 21
B. Fuel Cells ........................................................................................................................... 22
1. Fuel Cell Technology Review ........................................................................................ 24
2. Fuel Cell Manufacturers ................................................................................................. 25
3. Case Study for Gustavus ................................................................................................ 25
4. Hydrogen Future ............................................................................................................ 26
C. Southeast Alaska Intertie (Submarine Cable) ................................................................... 26
D. Energy Efficiency .............................................................................................................. 26
1. Tenakee Springs ............................................................................................................. 27
2. Efficiency Measures ....................................................................................................... 28
IV. Other Generation Technologies Considered ........................................................................... 30
A. Wind .................................................................................................................................. 30
B. Biomass ............................................................................................................................. 30
1. Bio-gasification .............................................................................................................. 32
2. Direct Combustion with Steam Turbine ......................................................................... 32
3. Direct Combustion with Hot Air Engine ........................................................................ 32
C. Biodiesel/Fish Oil .............................................................................................................. 32
D. Higher Efficiency Diesels ................................................................................................. 34
E. Micro Hydro ...................................................................................................................... 37
V. Conclusion ............................................................................................................................... 38
VI. Sources ...................................................................................................................................... 1
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I. Executive Summary
This report presents an analysis of viable economic alternatives to the 800 kW run of the river Falls
Creek Hydro Project (FERC Project No. 11659) proposed by Gustavus Electric Company. We
conclude that the Preliminary Draft Environmental Assessment and the Draft Project Application
are extremely optimistic in estimating the generating costs of the Falls Creek Project and that the
project is likely to increase rather than decrease existing rates. Similarly, the Federal Energy
Regulatory Commission (FERC) and the National Park Service (NPS) just issued the October 2003
Draft Environmental Impact Statement (Draft EIS) for the Falls Creek Project, which found
negative economic benefits under eight of nine scenarios evaluated. We therefore believe the
project has failed to meet specific standards in the applicable legislation (see below) that require
that the project can be completed in an economically feasible manner.
There is no pressing need for the project, as existing resources can easily meet the electric demand
in Gustavus for many years. We are sympathetic to the desire to decrease Gustavus’s reliance on
diesel fuel, given its volatile prices and air emissions. However, the Falls Creek project is an
extremely expensive and risky means of achieving this goal. On the other hand, promising
alternative technologies have the potential to provide both economic and environmental benefits in
the near future without irreversibly impacting a site inside a national park. We therefore suggest
that the best option is to give these alternative technologies several years to improve and develop
before making a substantial and irreversible commitment to Falls Creek.
Gustavus Electric estimates a total project cost of $5.1 million, with annual costs of approximately
$600,000 or $0.15/kWh. The proposed site is located on the Kahtaheena River, also known as Falls
Creek, within the boundary of Glacier Bay National Park and the Glacier Bay Wilderness Area.
The Glacier Bay Boundary Adjustment Act of 1998 authorizes a land exchange to allow for
development of a hydro project within Glacier Bay National Park in the event the project is licensed
by FERC. The act specifically requires that the project be economically feasible and that FERC
approve the project’s financial plan. Several parties, including the Sierra Club, the sponsor of this
report, oppose the project due to its location within a national park, as well as environmental,
aesthetic and economic concerns.
The estimates of load growth and generating costs made by Gustavus Electric are unreasonably
optimistic and fail to consider a full range of possible scenarios. We estimate initial generating
costs in the rage $0.30/kWh as opposed to Gustavus Electric’s estimates of $0.15, which does not
compare favorably to the alternative of diesel generation at costs of $0.17-$0.20/kWh (including
capital recovery). This is primarily due to two assumptions; that load will grow at a slower rate
than forecast by Gustavus Electric and that it is unlikely that the National Park Service (NPS) will
choose to be served by Gustavus Electric. Furthermore, the project will dramatically increase the
size of Gustavus Electric, raising capital assets from under $1 million to over $5 million. Without
state or federal funding (for which no specific sources have yet been identified), this will increase
Gustavus Electric’s rate base and add $0.05/kWh, and possibly much more, to electric rates. Other
factors, such as higher minimum instream flow requirements and higher financing costs also have
the potential to increase the rate impacts of the Falls Creek Project.
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The October 2003 Draft EIS estimates average power costs of around $0.21/kWh over the first 10
years of the project, and that is if park service load is included. Under a range of load growth
scenarios, the Draft EIS finds that the cost of Falls Creek power is, on average, $0.09 - $0.11/kWh
higher than the alternative of diesel generation over the first 10 years of the project (or $0.13-
$0.17/kWh higher without park service load). Only under a scenario of high load growth, high
diesel fuel cost increases, and including park service load did the Draft EIS find positive economic
benefits (and then of only $23,000 per year or $0.006/kWh, beginning in 2016). Under the most
likely scenarios, the project will not show economic benefits until after 2018 or later.
Both this paper and the Draft EIS analysis find that the Falls Creek project fails to pass the test of
economic viability required for approval by the Glacier Bay Boundary Adjustment Act. Given the
lack of urgent need for power and the questionable economics of the Falls Creek Project, there is a
good argument for deferring the Falls Creek project for several years to evaluate potential
alternatives that are showing promise. Demonstration projects for tidal technologies in Alaska and
British Columbia as well as other parts of the US are currently in advanced stages of
implementation and several manufacturers argue they can generate electricity under $0.10/kWh.
Fuel cells are installed at over 650 sites worldwide and manufactures are investing heavily to
develop commercially viable units. These technologies show promising potential to provide
economic and environmentally sensitive generation for Gustavus without irreversibly
compromising a site inside a national park. Interconnection via submarine cable to the Hoonah leg
of the proposed Southeast Intertie also presents a potential alternative, though only with sufficient
federal and state funding. Independent of the above alternatives, energy efficiency initiatives
implemented in other rural Southeast Alaska towns could reduce Gustavus’s energy consumption
by as much as 30 percent, further deferring the need for investment in new generating resources.
Figure 1 below provides an overview of alternatives described above. The numbers represent
approximate cost estimates made by a number of manufacturers and researchers for the
technologies. Costs for tidal energy and fuel cells are expected to decline significantly in the near
future, though costs for Gustavus are likely to be somewhat higher than elsewhere due to the
relatively small load and remote location.
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Figure 1
Summary of Economic Alternatives
Source $/kW $/kWh Comments
Falls Creek Hydro $5,163 ~$0.30 Proven existing technology. May be little or no
firm capacity in low flow Summer months.
Tidal Energy $1,400-
$3,000
$0.06-
$0.15
Several demonstrations in development.
Promising, but not commercially proven. Cost
may be higher for the small scale development,
required in Gustavus.
Fuel Cell $4,500. ~$0.16. Over 650 installed world wide. Some
technological and cost issues must be overcome
for widespread commercial use. Large propane
reformers needed for use in Gustavus are in
development, but not yet available.
Southeast Intertie $23,000 ~$0.30 +
purchased
power
costs
Existing technology, extremely high capital
investment. Some federal funds promised, but
additional state funds needed.
Energy Efficiency $2,000 N/A Proven existing technology implemented in
other SE Alaska towns. State funds may
become available.
Gustavus Electric already charges rates that are 20 to 50 percent higher than comparable utilities in
Southeast Alaska. Gustavus Electric’s reported non-fuel power costs are over 50 percent higher
than the costs of the next highest utility. The Regulatory Commission of Alaska (RCA) recently
opened a rate case for Gustavus Electric (Docket U-03-17) and Gustavus Electric still has not filed
updated financial information that was due to the RCA in July 2003. FERC does not normally
examine retail electric rates as part of its licensing process. However, the Glacier Bay National
Park Boundary Adjustment Act requires Gustavus Electric to submit an acceptable financing plan to
FERC before initiating construction and retail rates are an integral part of the financing of any
utility project. FERC should therefore require a full analysis of the rates that Gustavus Electric will
have to charge its customers to pay for the project and assess the impact of those rates on the
community already burdened by high energy costs.
In conclusion, Falls Creek would commit $5 million to a project of dubious need or economic
benefit with little or no firm capacity in low flow summer months. Falls Creek would irreversibly
impact a site within a national park and preclude investment in alternative sources of generation for
decades to come. Instead, we suggest that Gustavus invest in energy efficiency, which will further
defer the need for new generation. With or without investment in efficiency, Gustavus has at least
five years in which the community can safely pursue promising alternatives, such as tidal energy
and fuel cells. These technologies stand a good chance of providing economic and environmentally
sound energy in the near future and will have little or no adverse or irreversible impact in Glacier
Bay National Park.
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II. Falls Creek Project Economics
A. Applicable Legislation
Conclusion: The Glacier Bay National Park Boundary Adjustment Act contains specific
requirements over and above other applicable legislation for Gustavus Electric to show that the
Falls Creek Project can be completed in an economically feasible manner. Both this analysis
and the October 2003 Draft EIS show that this burden has not been met.
This section highlights legislation that is particularly relevant to economic issues that must be
considered by FERC in considering the Falls Creek Hydro Project. The Glacier Bay National Park
Boundary Adjustment Act of 1998 contains additional requirements more stringent that those in the
Federal Power Act and National Environmental Policy Act normally considered by FERC.
The Federal Power Act, Section 10 (a) 2 (C) states that FERC shall consider:
“…the electricity consumption efficiency improvement program of the applicant, including
its plans, performance and capabilities for encouraging or assisting its customers to conserve
electricity cost-effectively, taking into account the published policies, restrictions and requirements
of relevant State regulatory authorities applicable to such applicant.” (Emphasis added)
The Federal Power Act, Section 15 (a) 2 states that FERC shall consider:
(C) The plans and abilities of the applicant to operate and maintain the project in a
manner most likely to provide efficient and reliable electric service.
(D) The need of the applicant over the short and long term for the electricity generated
by the project or projects to serve its customers, including, among other relevant
considerations, the reasonable costs and reasonable availability of alternative sources of
power, taking into consideration conservation and other relevant factors and taking into
consideration the effect on the provider (including its customers) of the alternative source of
power, the effect on the applicant’s operating and load characteristics, the effect on
communities served or to be served by the project…”
(E) The existing and planned transmission services of the applicant, taking into
consideration system reliability, costs and other applicable economic and technical factors .
(F) Whether the plans of the applicant will be achieved, to the greatest extent possible,
in a cost effective manner.” (Emphasis added)
The above statues clearly require Gustavus Electric to show the proposed Falls Creek Hydro Project
provides generation that is required by the community in Gustavus and provides that generation in a
reasonable and cost effective manner. The statues also clearly require FERC to consider alternative
sources of power, including conservation, Gustavus Electric’s arguments for not including
conservation as an alternative notwithstanding.
The National Environmental Policy Act, as implemented in US Code, Title 42, Chapter 55, Section
4332, Paragraph 2 (C) states,
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All agencies of the Federal Government shall include in every recommendation or report on
proposals for legislation and other major Federal actions significantly affecting the quality
of the human environment, a detailed statement by the responsible official on
(iv) the relationship between local short-term uses of man's environment and the
maintenance and enhancement of long-term productivity and
(v) any irreversible and irretrievable commitments of resources which would be
involved in the proposed action should it be implemented.
The Falls Creek Hydro Project would irreversibly commit both natural and economic resources
significant to the community of Gustavus. The project would commit Gustavus to expensive hydro
generation to the exclusion of more environmental and economic alternatives that may be available
in the near future. The National Environmental Policy Act clearly requires an environmental and
economic assessment that weights the benefits of the proposed project against current and potential
future alternative options for serving the power needs of Gustavus.
In addition, the Glacier Bay National Park Boundary Adjustment Act of 1998, Section 2 (c) states:
“(c) CONDITIONS- Any exchange of lands under this Act may occur only if--
(1) following the submission of a complete license application, FERC has conducted
economic and environmental analyses under the Federal Power Act (16 U.S.C. 791-
828) (notwithstanding provisions of that Act and the Federal regulations that
otherwise exempt this project from economic analyses), the National Environmental
Policy Act of 1969 (42 U.S.C. 4321-4370), and the Fish and Wildlife Coordination
Act (16 U.S.C. 661-666), that conclude, with the concurrence of the Secretary of the
Interior with respect to subparagraphs (A) and (B), that the construction and
operation of a hydroelectric power project on the lands described in section 3(b)--
(A) will not adversely impact the purposes and values of Glacier Bay
National Park and Preserve (as constituted after the consummation of the
land exchange authorized by this section);
(B) will comply with the requirements of the National Historic Preservation
Act (16 U.S.C. 470-470w); and
(C) can be accomplished in an economically feasible manner;
(2) FERC held at least one public meeting in Gustavus, Alaska, allowing the citizens
of Gustavus to express their views on the proposed project;
(3) FERC has determined, with the concurrence of the Secretary and the State of
Alaska, the minimum amount of land necessary to construct and operate this
hydroelectric power project; and
(4) Gustavus Electric Company has been granted a license by FERC that requires
Gustavus Electric Company to submit an acceptable financing plan to FERC before
project construction may commence, and the FERC has approved such plan.”
(Emphasis added)
The Glacier Bay National Park Boundary Adjustment Act further emphasizes that an economic and
environment analysis is required. In addition, the Glacier Bay National Park Boundary Adjustment
Act specifically requires that the project can be accomplished in an economically feasible manner.
Furthermore, the above statues specifically require Gustavus Electric to submit a financing plan for
review by FERC. Both of these requirements place an increased burden on Gustavus Electric to
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show, and on FERC to find with some degree of certainty and specificity, how the project will be
financed and how the project will provide economic benefits to the community of Gustavus.
In the following sections we will show not only that this burden has not been met, but that the
project is likely to have negative economic benefits. Even appendices to Gustavus Electric’s
Preliminary Draft Environmental Assessment (Draft EA) state “the cumulative benefits are negative
due to the high capital costs of the project”.1 The report indicates that for the project to provide
savings by year five of its operation, the project costs would have to be lowered from the current $5
million estimate by 42 percent, to $3.4 million. The same Appendices also show that the load
growth projections provided by Gustavus are unreasonably high and that there is no need for
additional generation in the near future. We also show that it is highly likely that the Falls Creek
Hydro Project will significantly increase rather than reduce electric rates in Gustavus, which are
already 20-50 percent higher than comparable utilities in Southeast Alaska.
B. Gustavus Electric Demand and Load Growth
Conclusion: because the generation of the Falls Creek Project will be limited not by the project’s
capacity, but electric demand in Gustavus (and possibly Glacier Bay National Park) the project
economics are extremely sensitive to load growth projections (The October 2003 Draft EIS also
emphasizes this point). The Project Application considers only the most optimistic load growth
scenario. There are several reasons load growth is likely to be lower than projected by Gustavus
Electric and even the October 2003 Draft EIS, which would dramatically increase projected
generating costs.
The Preliminary Draft EA states that “GEC is expected to have adequate capacity throughout the
study period with only the existing resources” (p. 23). The Power Requirements Study in Appendix
B of the Preliminary Draft EA presents a low, middle and high case for load growth forecasts. The
high case assumes an average annual load growth of 5.72 percent, compared to 3.71 and 3.84 for the
low and middle cases. We assume, as does in the Power Requirements Study, that Gustavus
Electric’s peak load of 350 kW grows at the same rate as annual loads. Under the high load growth
scenario, peak loads will not surpass the combined capacity of Gustavus Electric’s two primary
diesel generators (Units 1 and 3 at 550 kW) until 2011 (Figure 2). Under the low and middle cases
the cross over point does not occur until 2014. Furthermore, in addition to the two primary units
considered here, Gustavus Electric has an additional 500 kW diesel generator (Unit 4) that is
currently used when the primary units are off-line for maintenance and a 100 kW diesel generator
(Unit 2) that is seldom used.
A hydro facility would reduce the price volatility and air emissions associated with diesel
generation, but at an extremely high cost. Given that there is no pressing need for additional
generating capacity, Gustavus Electric must show that the Falls Creek Hydro project will provide
economic and environmental benefits as compared to existing and potential future technology that
could be implemented before 2014. We do not believe Gustavus Electric has made a sufficient
showing in this regard.
1 Appendix B to EA, Page VI-I, Summary and Conclusions
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Figure 2
Peak Load Growth
-
100
200
300
400
500
600
700
800
900 200720082009201020112012201320142015201620172018kWHigh
Mid
Low
Diesel Cap.
The forecast of annual electric loads provided in the Preliminary Draft EA now appear to be
unrealistically high. That document shows an electric load of 1,694 MWh in 2000 and projects a
load of 2,670 MWh in 2007, an annual increase of 6.72 percent. In fact, loads have actually
declined since the report was published in May 2001. Since 1997 the annual load has never
increased more than 2.78 percent and annual loads actually decreased between 1999 and 2001
(Figure 3). Since 2001, utilities through out the US have revised their load forecasts downward to
reflect reduced economic activity. US Department of energy forecasts load growth of less that 1.1
percent for the next two years (Short-Term Energy Outlook -- August 2003, Energy Information
Administration).
Interestingly, the 2,670 MWh figure for Gustavus loads in 2007 in the Preliminary Draft EA is even
higher than the high case of 2,390 MWh from the Power Requirements Study presented later in
Appendix B of the Preliminary Draft EA. The high case assumes an average annual load growth of
5.72 percent, compared to 3.71 and 3.84 for the low and middle cases.
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Figure 3
Gustavus Electric Historical Monthly and Annual Sales
60,000
70,000
80,000
90,000
100,000
110,000
120,000
130,000
140,000
150,000
160,000Jan-90Jan-91Jan-92Jan-93Jan-94Jan-95Jan-96Jan-97Jan-98Jan-99Jan-00Jan-01Jan-02Jan-03Monthly Sales (kWh)720,000
920,000
1,120,000
1,320,000
1,520,000
1,720,000
1,920,000
Annual Sales (kWh)Actual Monthly Sales Annual Sales
Figure 4 shows the projected load growth beginning with actual 2002 sales of 1,400 MWh and
using the percent load growth from the Power Requirements Study in the Preliminary Draft EA,
Appendix B. As the figure shows, even the high case projects substantially lower loads that those
presented in the body of the Preliminary Draft EA. Because the useful generation of Falls Creek
project will be limited by loads in Gustavus, the rates of load growth assumed in the study
significantly impact the economics of the proposed project, as shown in the next section.
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Figure 4
Gustavus Electric Historical Sales and Load Forecast
100,000
600,000
1,100,000
1,600,000
2,100,000
2,600,000
3,100,000
3,600,000Jan-90Jan-91Jan-92Jan-93Jan-94Jan-95Jan-96Jan-97Jan-98Jan-99Jan-00Jan-01Jan-02Jan-03Jan-04Jan-05Jan-06Jan-07Jan-08Jan-09Jan-10Jan-11Jan-12Jan-13Jan-14Jan-15Jan-16Annual Sales (kWh)Annual Sales EA Forecast PR Low PR Mid PR High
EA Forecast: from Preliminary Draft Environmental Assessment
PR Forecasts: based 2002 actual kWh sales and on load growth percentages from Power Requirements Study,
Preliminary Draft Environmental Assessment, Appendix B
The Preliminary Draft EA also argues that the tourism industry will protect the town from the
decline in economic activity seen in other Southeast Alaska towns as a result of declining lumber
and fish processing in the area. However, travel and tourism has decreased since 2001 in Alaska as
it has throughout the US as a result of a slow economy and heightened security concerns.
According to the Alaska Department of Community and Economic Development, vacation and
pleasure travel in Alaska actually decreased in 2002 (Alaska Department of Community and
Economic Development, 2003).
The October 2003 Draft EIS also makes assumptions about load growth that may be too high. The
Draft EIS notes that load has grown an average of 8.1 percent from 1985 to 2002. However, 1985
coincides with the implementation of the Power Cost Equalization Credit, which significantly
reduced electric rates seen by customers in Gustavus. The Draft EIS assumes load growth of 4
percent for the next decade. Since 1990 load growth has averaged 4.1 percent, including several
significant jumps in 1992, 1994 and 1996. However, since 1997 load has not increased by more
than 3 percent and actually decreased in several years. Since 1997 the Power Cost Equalization
Credit for commercial customers has been discontinued and portions of Glacier Bay National Park
have been closed to commercial fishing. Also the rate of population and load growth tends to
decline as small towns get larger as Gustavus has. Gustavus’s population grew from 98 in 1980 to
258 in 1990 (a 163 percent increase) and to 429 in 2000 (66 percent increase). Finally the Draft EIS
assumes annual generation of 1,638 MWh in 2002, while documents provided by the Regulatory
Commission of Alaska indicate annual sales of 1,404 MWh in 2002, nearly 15 percent lower.
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Gustavus Electric argues that when hydro projects have been completed in other areas of Alaska,
electric demand increased significantly. However, there are several reasons this may not occur in
Gustavus. In most cases hydro is cheaper than the existing resources, leading to an immediate
reduction in electric rates, which in turn spurs increased demand. In the case of Gustavus, because
the Falls Creek Project is relatively expensive and generation is limited by the demand for
electricity, not the project’s capacity, the Falls Creek project will not lower rates unless demand
increases. Consumers would have to increase electric usage on the promise that rates will decrease
in the future as a result. Furthermore, generation from the Falls Creek project would not be eligible
for Power Cost Equalization Credits, as is the current diesel generation. This would lead to a
reduction in the total Power Cost Equalization credit seen by customers. Some customers may be
willing to use more electricity because it is from a cleaner source that diesel, but there is certainly
some limit to the additional cost these customers would be willing to incur. Studies have indicated
many customers are willing to pay a few cents more per kWh for green power, but both this study
and the October 2003 Draft EIS suggest costs for the Falls Creek Project are likely to be $0.09-
$0.15/kWh (or 50-80 percent) higher, if not more, than diesel.
C. Falls Creek Construction and Operating Costs
Conclusion: The generation costs proposed by Gustavus Electric are based on extremely
optimistic assumption. More realistic assumptions show that the Falls Creek Hydro Project is
likely to generate electricity at costs significantly higher than that of existing or new diesel
generation.
The Preliminary Draft Environmental Assessment forecasts costs of $0.089/kWh for the Falls Creek
Project (Section IV – Generating Alternatives Overview). The Draft Project Application projects
costs of $0.15/kWh in the first year (Section 3.2 Annual Costs). However this projection assumes
an extremely high load growth projection and utilization of 5.5MWh and include Park Service load.
The actual project generation will be limited primarily by the demand for electricity in Gustavus,
making the cost of power extremely sensitive to load growth projections.2 The load for Gustavus
alone is estimated in the Preliminary Draft EA at 2,670 MWh in 2007, growing to 3,610 in 2017.3
Given that the Falls Creek project will provide power only when water flows allow, we assumed a
best case 82 percent of the Gustavus load could be served by the Falls Creek Project.4 Given
proposed minimum instream flow requirements, the Draft EIS assumes the Falls Creek Project can
serve 78-80 percent of Gustavus’s load, while Gustavus Electric assumed a level over 90 percent.
Without park service load (see below), the amount of energy useable in this scenario is 2,270 in
2007, with an average of 2,670 and a cost per kilowatt-hour of 18.4 cents over the first 10 years of
the project. This is higher than the power costs of $0.17/kWh reported in Section 3.2 of the Draft
Project Application for existing diesel generation in Gustavus and not much less than the costs of
around $0.20/kWh reported by the park service (see Diesel Technology Section below).
However, as explained in the previous section, actual loads are likely to be far less than projected by
the Preliminary Draft EA in May 2001. Figure 5 shows the projected load growth using the
percentage load growth figures from the Power Requirements Study, beginning with actual 2002
2 Appendix B to EA, Page IV-9
3 EA, Page A-9, Table A-4
4 2007 ratio from EA, Page A-9, Table A-4
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generation of 1,400 MWh. Again, we assume that at most 82 percent of Gustavus’s load can be
served by the Falls Creek Project. Using these figures it does not appear that the Falls Creek Hydro
Project will be economic until 2018 under low or mid range growth projections.
Figure 5
Projected Gustavus Load Growth
2002 Load (MWh) 1,400
Percent served by Falls Creek 82%
Annual Operating Costs $460,000
Projected Load Growth Projected Load $/kWh
Low Mid High Low Mid High Low Mid High
2000 4.23% 4.66% 5.90%
2001 4.16% 4.62% 5.88%
2002 4.09% 4.58% 5.85%
2003 4.01% 4.55% 5.82% 1,456 1,464 1,482
2004 3.94% 4.51% 5.79% 1,514 1,530 1,567
2005 3.87% 4.47% 5.76% 1,572 1,598 1,658
2006 3.80% 4.44% 5.74% 1,632 1,669 1,753
2007 3.73% 4.40% 5.71% 1,693 1,743 1,853 0.33 0.32 0.30
2008 3.66% 4.36% 5.68% 1,755 1,819 1,958 0.32 0.31 0.29
2009 3.63% 3.76% 5.68% 1,818 1,887 2,069 0.31 0.30 0.27
2010 3.61% 3.24% 5.69% 1,884 1,948 2,187 0.30 0.29 0.26
2011 3.58% 3.24% 5.69% 1,952 2,011 2,312 0.29 0.28 0.24
2012 3.56% 3.24% 5.69% 2,021 2,076 2,443 0.28 0.27 0.23
2013 3.54% 3.24% 5.69% 2,093 2,144 2,582 0.27 0.26 0.22
2014 3.50% 3.21% 5.67% 2,166 2,212 2,728 0.26 0.25 0.21
2015 3.46% 3.18% 5.65% 2,241 2,283 2,883 0.25 0.25 0.19
2016 3.41% 3.16% 5.63% 2,317 2,355 3,045 0.24 0.24 0.18
2017 3.37% 3.13% 5.61% 2,395 2,429 3,216 0.23 0.23 0.17
2018 3.33% 3.10% 5.58% 2,475 2,504 3,395 0.23 0.22 0.17
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Figure 6
Generating costs under
Low, Mid and High Load Growth Scenarios
0.10
0.15
0.20
0.25
0.30
0.35 200720092011201320152017$/kWhLow
Mid
High
Gustavus Electric proposes that the Falls Creek Project could also serve the Park Service load.
However, it is misleading to include such an assumption in the Preliminary Draft EA without also
including the additional costs associated with serving the Park Service. The Preliminary Draft EA
makes no estimate of the cost of building the transmission line between Gustavus and Park Service
Headquarters. More importantly, in discussion with Park Service personnel, they indicated that
they recently made significant capital investments in their diesel generation system, which is
capable of serving their needs for some time. The total cost was estimated at $0.20/kWh, with
$0.08/kWh of this representing capital and operating expenses. If the system were idled due to
interconnection with Gustavus, the capital cost of the system would be unrecoverable. Therefore,
any economic evaluation that includes the Park Service load should address this cost of stranded
capital.
D. Financing and Rate Calculations
Conclusion: Absent state or federal funding, for which there is no specifically identified source,
the cost of financing the Falls Creek Project is likely to be higher than the 7 percent assumed in
the project application. Again, absent government funding, the $5 million project will also
substantially increase Gustavus Electric’s rate base (currently under $1 million), increasing rates
by $0.05/kWh and possibly much more.
Utilities typically finance the construction of capital assets such as generating plants and
transmission lines with a combination of debt and equity. The utility pays interest for debt such as
bonds or bank loans, which typically provides 40-60 percent of the investment in a new project.
The remaining portion is financed with equity, capital provided by the owners or shareholders of the
utility in return for which the owners or shareholders expect a return on their investment. Debt is
less risky and therefore less costly than equity financing, but the cost of debt rises with the
14
proportion of the investment that is financed with debt. Projects may be financed with as much as
80 percent debt or even more, but the more debt and less equity invested in a project, the greater the
risk of default, and banks and bond holders will require a higher interest rate to compensate for the
higher risk. This is comparable to a home loan; the lower the down payment (or equity) invested by
the buyer, the higher the interest rate charged by the bank for the home loan. Companies will
generally try to find the balance of debt and equity that minimizes their overall cost of financing the
project.
The Draft Project Application assumes that the project is 100 percent debt financed at an interest
rate of 7 percent. The Draft EIS recently issued by the FERC and the NPS assumes an interest rate
of 8 percent. However, absent grants or low interest loans, this would appear to be a low cost of
capital for project such as Falls Creek, which is quite large for a relatively small utility such as
Gustavus Electric. Furthermore, such low interest rates are predicated on the assumption that the
lender is quite confident in the economic feasibility of the project. Thirty year bonds for large
investment grade companies currently have yields of 6-7 percent and large companies with lower
ratings must pay 8 percent or more. Smaller companies, companies financing projects considered
more risky by lenders and companies financing new projects with a high percentage of debt usually
must pay higher rates. To achieve a lower cost of debt, Gustavus Electric must secure grants or
low interest loans, or invest its own equity in the project. However, any portion of the project that
is financed with equity by the owners of Gustavus Electric will require even higher rates of return,
typically in the 10-15 percent range for electric utilities (see discussion of authorized rate of return
in next paragraph). If Gustavus Electric is successful in securing federal or state funding for all or a
significant portion of the project, the cost of financing could be significantly reduced. However,
absent clear evidence that such funding is available, it is reasonable to assume that the cost of
financing the Falls Creek will be higher than 7 percent. A 2 percent increase in the cost of capital
results in a $0.03/kWh increase in power costs in 2007 assuming a load of 2,670 MWh. However,
as explained above, we believe the 2,670 MWh load projection to be unreasonably optimistic; at
lower loads the increase in power costs would be closer to $0.05/kWh.
Investments made by the utility contribute to the utility’s rate base; the capital investment for which
the utility earns an authorized rate of return approved by a regulatory commission. This return is
designed to provide an adequate incentive for utilities to make the capital investments necessary to
provide sufficient and reliable generation, while protecting consumers from unreasonably high rates
that an unregulated monopoly might otherwise charge. Authorized rates of return can vary
considerably, but are typically in the range of 9-15 percent.
The Falls Creek Hydro Project will profoundly impact the rate base that is used to calculate the
authorized return allowed for Gustavus Electric. Any equity investments made by Gustavus
Electric will go directly towards the rate base, as described above. As Gustavus Electric repays the
principle of any debt, that will increase Gustavus Electric’s ownership or equity in the project and
therefore increase the utility’s rate base.
The Falls Creek Project has already had a substantial impact on Gustavus Electric’s balance sheet,
which showed fixed assets of $670,534 in 2000 and $1,000,677 in 2002. As shown in Figure 7, this
50 percent increase is due primarily to expenditures related to the Falls Creek Hydro Project.
Because the total cost of the project ($5 million) is quite large in comparison to Gustavus Electric’s
existing assets ($1 million), absent state or federal funding, the project would significantly increase
the utility’s rate base and therefore its electric rates.
15
Figure 7
Gustavus Electric Fixed Assets
2000 2001 2002 Change
Office Equipment $42,917 $48,941 $49,968 $7,051
Misc. Intangible Plant 88 88 88 -
Hydro Electric Plant 240,111 584,864 708,266 468,155
Misc. Equipment 9,630 11,639 13,695 4,065
Fuel Tanks 1,930 1,930 1,930 -
Generators 218,763 220,092 237,789 19,026
Buildings - Structures 168,324 168,324 168,624 300-
Accessory Electrical Equipment 214,088 241,088 241,088 27,000
Station & Substation 13,339 13,339 13,339 -
Overhead Lines 34,599 61,599 61,599 27,000
Underground 361,957 361,957 361,957 -
Transformers 225,964 225,964 225,964 -
Services 145,999 145,999 145,999 -
Meters 57,637 57,637 57,637 -
Transportation Equipment 50,870 50,870 62,801 11,931-
Power Operated Equipment 67,071 67,071 74,114 7,043-
Accumulated Depreciation (1,236,755) (1,328,272) (1,424,382) (187,627)
Total Fixed Assets $670,534 $933,132 $1,000,677 $330,143
In 1989, the Regulatory Commission of Alaska (RCA) found that a 6.5 percent return on a rate base
of $325,000 (or $21,101) was reasonable. This amounted to approximately $0.03/kWh with annual
generation of 644,302 kWh in 1989. Even if only 30 percent of the construction cost is eventually
included in rate base, a 6.5 percent return would amount to approximately $80,000 (as stated above,
returns above 10 percent are commonly found reasonable). Again this would increase rates by
approximately $0.03/kWh at loads of 2,670 MWh and $0.05/kWh at lower demand levels.
We are sensitive to the desire to utilize hydro generation to reduce Gustavus’s dependence on often
volatile diesel prices and to reduce the air emissions associated with diesel generation. If, as we
find, the Falls Creek Hydro Project is not likely to produce electricity at rates lower than existing
facilities, that removes one of Gustavus Electric’s primary arguments supporting the project; that it
will reduce generating costs. The Final EA should present a much more realistic picture of the
generating cost of the Falls Creek Project and include generating costs under a range of likely
scenarios, not just the most optimistic.
E. Falls Creek Hydro Project Firm Capacity
Conclusion: As a run-of-the-river hydro plant, the Falls Creek Project generation may be
severely limited by available stream flow and minimum instream flow requirements, particularly
in the summer months. When considering alternatives, it is important to remember that the
Falls Creek project will not provide firm capacity year round, and will be supplemented by diesel
generation.
In is important to point out that generation from the Falls Creek Project will not be available
throughout the year and in some months may be quite limited. This is an important consideration
16
when comparing the Falls Creek Project to alternatives. One of the disadvantages of alternative
generating technologies when compared to more established technologies is that technologies like
solar, wind and tidal are less “firm” and more intermittent in nature. However this is not necessarily
the case when considering alternatives to Falls Creek. The Falls Creek Hydro Project is a run-of-
the-river project that will generate only when sufficient flow is available in the river. Gustavus has
proposed that the Falls Creek Project will be a load following project, that is follow the electricity
demand in Gustavus. However, state agencies have pointed out that it is often not possible for a
run-of-the-river project to follow load over the course of the day without some storage capacity,
which is not proposed for Falls Creek. Furthermore, some agencies are proposing minimum
instream flow requirements that may prevent the operation of the Falls Creek altogether in low flow
months. These agencies have also questioned the methods used to estimate the available flows in
the Kahtaheena River and suggested further study. All these issues suggest that the generation from
the Falls Creek Hydro Project will be intermittent in nature during some portion of the year and
require supplemental diesel generation. Acknowledging the intermittent nature of the generation
from the Falls Creek Hydro Project makes alternatives that are also intermittent in nature, such as
tidal, more competitive in comparison.
F. Gustavus Electric Rates
Conclusion: Gustavus Electric charges rates higher than comparable towns in Southeast Alaska.
While there may be good reasons for this, a recently initiated rate case may shed more light on
the issue. Furthermore, because rates are an integral part of financing this project, and FERC is
required to approve an acceptable financing plan, FERC must carefully consider the rate impacts
of this project.
Gustavus Electric Inc. charges some of the highest rates for electricity in Southeast Alaska.
Gustavus charges rates that are 20 to 50 percent higher than other suppliers of electricity to rural
towns in Southeast Alaska relying solely on diesel generation (Figure 8). Non-fuel power costs
listed in Power Cost Equalization calculations provided by the Regulatory Commission of Alaska
are over 50 percent higher than the next highest utility.
17
Figure 8
Comparison of Gustavus Electric Bills, Revenues and Costs
with other Southeast Alaska utilities relying solely on diesel generation
500
kWh
Bill
(1)
Revenue
¢/kWh (2)
Non-
Fuel
Power
Cost (3) Fuel Cost (4)
Annual
MWh
(5)
Res.
Com. ¢/kWh $/Gal
¢/kWh
Gustavus Electric Inc $248 49.8 42.1 35.4 1.49 13.3 1,466
Whale Pass(APC) 193 29.1 17.6 1.30 9.9
1,156 Naukati Bay(APC) 166 28.2 17.6 1.30 9.0
Coffman Cove(APC) 152 28.5 17.6 1.30 9.3
Tlingit & Haida Region El Auth 183 36.5 26.5 22.5 1.16 10.0 13,008
Tenakee Springs City of 159 31.8 31.8 17.3 1.53 15.6 393
Yakutat Power Inc 130 26.0 20.5 13.8 1.13 8.2 7,491
Elfin Cove City of 71 14.1 5.0 9.6 1.73 15.8 349
(1) Electric: Sample of Monthly Residential Rates, Regulatory Commission of Alaska Feb. 28, 2003
(2) U.S. Department of Energy, Energy Information Administration, Form EIA-861, 2000 data.
(Revenue for Alaska Power Company (APC) from Regulatory Commission of Alaska PCE Calculations
(3) Power Cost Equalization (PCE) Spreadsheets provided by the Regulatory Commission of Alaska, July 2003
(4) Cost of Power Adjustment (COPA) Spreadsheets provided by the Regulatory Commission of Alaska, July 2003
(5) Energy Information Administration, Form EIA-861 Annual Electric Utility Report, 2001 and
Power Cost Equalization (PCE) Spreadsheets provided by the Regulatory Commission of Alaska, July 2003
APC sales aggregated for North Prince of Whales Island (Whale Pass, Naukati Bay, Coffman Cove)
Gustavus Electric is a privately owned utility and is therefore regulated by the Regulatory
Commission of Alaska (RCA). The most recent breakdown of non-fuel costs that the RCA was
able to provide is from a 1989 rate case (Docket U-86-74, Order 2). Price of Wales Island is served
by the Alaska Power Company (APC), also a regulated utility. While towns in North Prince of
Wales Island rely solely on diesel generation, hydro power supplies a portion of the loads in South
Prince of Wales Island. Detailed non-fuel power cost data specific to the towns in North Prince of
Wales Island was not available. The remaining utilities in Southeast Alaska that rely solely on
diesel generation are cooperative or publicly owned, and therefore not regulated by the RCA.
However, non-regulated utilities provide updated non-fuel cost information each year in order to
receive Power Cost Equalization funds. Regulated utilities such as Gustavus Electric are not
required to provide updated cost data each year for Power Cost Equalization credits. The RCA did,
however, provide a 2001 income statement for Gustavus Electric from which we were able to
estimate most of the detailed non-fuel power costs (except for parts and supplies, which was not
listed separately).
Figure 9 shows a non-fuel power cost for Gustavus Electric from 1989 that is slightly lower, on a
cents per kWh basis, than the non-fuel power cost from the 2003 Power Cost Equalization
calculation shown in Table 1. Still Gustavus Electric’s non-fuel power cost is over 40 percent
higher than the next highest utility. Figure 10 shows that in each category for non-fuel power costs
(except Parts and Supplies in 1989 which was zero for Gustavus, and O & M in 2001); Gustavus
Electric is at or near the top of the list on a cents per kWh basis.
18
Figure 9
Comparison of Gustavus Electric Total Non-Fuel Power Costs
with Other Southeast Alaska Utilities Relying Solely on Diesel Generation
Non-Fuel Costs
Year
Reviewed kWh Sales
Total Non-Fuel
Costs (¢/kWh)
Gustavus Electric Inc (1) 1989 518,962 $167,386 32.3
Gustavus Electric Inc (2) 2001 1,603,200
Tlingit & Haida Region El Auth 2002 11,384,288 2,558,540 22.5
Tenakee Springs City of 2002 382,159 66,139 17.3
Yakutat Power Inc 2002 7,614,569 988,531 13.0
Elfin Cove City of 2002 348,849 33,593 9.6
(1) Regulatory Commission of Alaska, Docket U-86-74, Order 2 (for Gustavus Electric as a regulated utility)
(2) Gustavus Electric Profit and Lost Statement, 2001, provided by Regulatory Commission of Alaska
Otherwise Power Cost Equalization (PCE) Spreadsheets provided by the Regulatory Commission of Alaska, July 2003 (for all other
utilities, which are unregulated)
Figure 10
Detailed Comparison of Gustavus Electric Non-Fuel Power Costs
with Other Southeast Alaska Utilities Relying Solely on Diesel Generation
Non-Fuel Costs Labor
Parts &
Supplies O & M G & A Dep. Int. Exp Other
Gustavus Electric 1986 $54,527 $0 $21,013 $30,267 $40,174 $21,405 $0
Gustavus Electric 2001 205,054 14,270 90,676 91,513 28,723
Tlingit & Haida Region El Auth 531,252 37,953 221,099 762,858 563,342 361,950 80,086
Tenakee Springs City of 35,207 10,462 2,088 6,463 11,919 - -
Yakutat Power Inc 443,440 41,677 73,781 202,643 184,488 82,502 (40,000)
Elfin Cove City of 16,342 2,213 8,712 226 5,473 - 627
Non Fuel Costs (¢/kWh) Labor
Parts &
Supplies O & M G & A Dep. Int. Exp Other
Gustavus Electric 1986 10.5 0.0 4.0 5.8 7.7 4.1 0.0
Gustavus Electric 2001 12.8 0.9 5.7 5.7 1.8
Tlingit & Haida Region El Auth 4.7 0.3 1.9 6.7 4.9 3.2 0.7
Tenakee Springs City of 9.2 2.7 0.5 1.7 3.1 0.0 0.0
Yakutat Power Inc 5.8 0.5 1.0 2.7 2.4 1.1 -0.5
Elfin Cove City of 4.7 0.6 2.5 0.1 1.6 0.0 0.2
One of the arguments for hydro power is that it generally provides cheaper power than fossil fuel
based alternatives. However, in this case, we expect that the Falls Creek Hydro Project will
increase rather than decrease Gustavus Electric’s already high rates (see above).
Gustavus Electric argues that there are two main reasons its rates are higher than the other utilities
in this comparison. The first is that all the other utilities received significant state funding for their
generation and distribution systems, which Gustavus Electric did not. The second is that Gustavus
is much less centralized than other small towns, requiring many more miles of distribution lines.
Furthermore, much of Gustavus Electric’s distribution system in underground, which is less prone
to outages, but much more expensive as compared to overhead lines
19
The Regulatory Commission of Alaska has indicated that an examination of rates for Gustavus
Electric Company is underway (Docket U-03-17), which could shed some light on the reasons for
Gustavus Electric’s relatively high rates. Gustavus was required to file information supporting
revised rates by July 1, 2003 (as required by 3ACC 48.275(a)). Gustavus Electric has not submitted
the required filing and on August 29, 2003, Gustavus Electric filed a motion for an order extending
time for filing. Before granting Gustavus Electric a permit to develop the only site suitable to
provide Gustavus with conventional hydro power, FERC should receive a thorough justification of
the utility’s high rates relative to other utilities in the area as part of the required economic analysis
and financial plan.
20
III. Promising Alternative Sources of Electric Generation
A. Tidal
Conclusion: Given the strong currents in the area, tidal energy is a promising but not yet proven
resource. Several demonstration projects of a variety of technologies are underway in the US
and Canada and several manufacturers promise costs under $0.10/kWh. Though they may soon,
tidal technologies have not yet proven themselves in a commercial setting.
Tidal flows are significant in the Gustavus area, with four tides of up to 20 feet per day. Standard
navigation charts indicated maximum tidal currents in the Icy Strait of between 5 and 8 knots.
For purposes of exploring the tidal energy potential of the Gustavus area, we reviewed relevant
research and contacted leading companies. The companies we contacted were based upon: 1) the
respondents to the Canadian province of British Columbia’s recent request for proposals (RFP) for
renewable energy including tidal and wave and 2) the city of San Francisco’s recent work on tidal
flow generators in the Golden Gate, 3) our review of UK tidal energy projects.
Of the four companies contacted, three responded to our request, UEK, Tidal Electric and Hydro
Venturi. Of these, Tidal Electric’s Peter Ullman was very familiar with the Gustavus area and has
had conversations with Gustavus Electric’s President, Dick Levitt and spent some time with the
head of the Glacier National Park. He mentioned that he also has spoken with the Sierra Club
regarding the tidal potential of the area. His comments indicated that excellent tidal resources exist
in the area and he believed that they could be economically developed. However, he felt that it was
not worth spending a lot of time on the feasibility issues without a local partner, principally
Gustavus Electric.
Hydro Venturi’s Joseph Neil also responded that the potential of the area was significant and that
they are putting a strategic focus on BC and Alaska projects. He indicated that the best way to
move forward would be to find a local partner with which to form a joint venture to explore the
opportunity further.
1. Tidal Energy Costs
Detailed assessments of the tidal flows around Gustavus are not available. Therefore, our general
discussions below are based upon work done in British Columbia5. The best tidal resource
identified in British Columbia is Discovery Strait.
In an October 2002 report, Triton Consultants, Ltd. calculated that using current technology, a tidal
farm consisting of 800 one-megawatt turbines at this location could produce power for 30 years at 8
cents per kilowatt-hour. Triton also estimated the cost of a smaller 43 Megawatt installation at Race
Passage at a cost of 18 cents per kilowatt-hour. The difference is principally due to the economies
of scale accruing to a large facility. Gustavus’s power needs would be served by a much smaller
and therefore more costly implementation than either of the above scenarios. However, other
technologies described below promise lower costs at smaller sizes as well (See below).
5 See “Green Energy Study for British Columbia, Phase II: Mainland, Tidal Current Energy”, for BC Hydro by Triton
Consultants, October 24, 2002
21
Future costs of tidal technologies are expected to drop. Specifically, the Triton report indicates that
within a few years cost of between 5 and 7 cents per kilowatt-hour may be achievable for large tidal
farms. This estimate is based upon the fact that tidal technologies have and will continue to mature
rapidly over the next few years. The technology and costs for converting tidal energy to grid ready
electricity can also present challenges, particularly for small projects. While several tidal
technologies are being test deployed, there are currently no commercial tidal energy production
facilities in operation. Given the above, we view the tidal energy as an option to be monitored and
explored further as the technologies mature, rather than a current opportunity.
2. Tidal Technologies
UEK of Annapolis Maryland manufactures turbines that are designed to
deliver 90 kW in a 5 knot current. Discussions with Philippe Vauthier
of UEK indicated that they are installing 3 ten ft. diameter units for a
total of 270 kW on the Yukon River in Eagle, AK. Installed costs are
estimated at $1,400/kW. The installation includes protective fish
screens.
Marine Current Technologies of London utilizes a single monopole to
mount dual 300kW turbines. These turbines can be raised to the surface
for maintenance and include innovative variable pitch blades. The
company has received UK government support and is developing a
prototype installation in South West England. The turbines require large
areas of relatively shallow water with little navigation or submerged
debris – potentially a problem around Gustavus.
Hydro Venturi of London manufactures a turbine
generator with no moving parts. The technology
relies upon the Bernoulli principal to compress air,
which is then piped to shore to run an on-shore
generator. Since there are no moving parts, Hydro
Venturi claims the device is more environmentally
benign, reliable and economic than other turbine
generators. San Francisco recently approved $2
million to study the use of this technology in San
Francisco Bay and Hydro Venturi believes the
project could be operation within 15 months.
22
Tidal Electric offers a unique construction technique, rather than a
turbine technology. They utilize an offshore impoundment structure
rather than the more typical tidal barrage system. Standard low
head turbines are utilized for power production and undersea cables
carry the power to shore. Tidal Electric claims that the
impoundment structure is a more environmentally benign and
economically advantageous means of utilizing tidal resources than
barrage systems.
Blue Energy is developing a prototype 250 kW power
system for small to mid-sized communities. The unit will
be viable in ocean currents of 2 knots or greater, and a
depth of at least 30 feet. Blue Energy expects to a capital
cost of $1,200 per kW for large-scale facilities and $3,000
for small and midrange systems.
B. Fuel Cells
Conclusion: It is possible, but not certain, that fuel cells will become an economic as well as
environmental option for electrical generation in Gustavus in the near future. Fuel cell
technology is progressing rapidly and costs are declining, but currently available commercial
products of the appropriate size are relatively expensive and are not configured to utilize fuels
available in Gustavus (propane or diesel).
Fuel cells provide the highest efficiency in the conversion of fuel to electricity, often reaching 50
percent or more. In addition, fuel cells also provide much lower emissions than internal combustion
engines, although this is somewhat dependent upon the fuel type and pre-processing used. Heat
produced by a fuel cell can be easily captured and utilized for water and space heating, often
resulting in efficiency above 80 percent. Fuel cells have moved out of the laboratory and into the
real world; over 650 large stationary fuel cell system (>10 kW) have been installed world wide
(Fuel Cell Today 2003).
Fuel cells are currently expensive compared to existing generating technologies. Studies cite
average costs around $4,500/kW, though costs vary widely among different sizes, technologies and
applications (Fuel Cell Today 2003, California Stationary Fuel Cell Collaborative 2002). To be
competitive with existing technologies, fuel cell manufactures expect that costs must drop closer to
$1,500/kW.
23
Figure 11
(California Stationary Fuel Cell Collaborative, 2002)
Many manufacturers and researchers believe that fuel cells are moving from field testing to
commercial viability quite rapidly and that technological advances and increased production levels
(with declining per unit costs) will lead to economically competitive models in less than five years.
Figure 11 presents the results of a 2002 survey of fuel cell manufactures, showing their expectations
of increased sales and declining costs in 2004 and 2005.
While the industry and many researchers present an optimistic picture, some researchers argue for
more caution. Demonstration projects and field tests have not been universally encouraging; the 2.5
kW fuel cell installed in Yellowstone National Park was removed after only five years after
becoming unreliable. Problems with stack degradation, durability and fuel impurities continue to
pose challenges, with no clear path to solutions say some researchers.
Bear in mind that much of what your read about fuel cells in the general media concerns
automobiles and that the challenges facing fuel cells for transportation are much more formidable
than those for stationary applications. While researchers estimate that fuel cell cars are at least ten
years and probably even further away (Despite Detroit and Washington’s declarations to the
contrary), stationary fuel cells will achieve commercial viability much sooner.
The ongoing fuel cost must be incorporated into the cost estimates for fuel cells. Currently
Gustavus has diesel and propane delivered via a barge to an offloading area on the Salmon River.
The diesel is used for the existing electrical production as well as for resident space heating. The
propane is primarily used for cooking.
Fuel cells run on hydrogen. Hydrogen is either provided directly from a source such as electrolysis
or is stripped from a fossil fuel such as natural gas or propane through a hydrogen reformer device.
24
Hydrogen reformers strip the carbon and other elements from the hydrocarbon fossil fuel. In this
process they generate waste, in the form of carbon dioxide and carbon monoxide. The vast majority
of reformers are designed to utilize natural gas. While not nearly as popular, some reformers are
available for propane and work is underway on
diesel reformers. Gustavus has no natural gas
infrastructure. Therefore, propane represents the
only currently available option for a fuel cell,
although diesel fuel may be useable in the near
future.
A limited number of propane-powered fuel cells
have been utilized in test as well as commercial
installations. For example, Yosemite Park installed
a 2.5 kW propane fuel cell manufactured by Plug
Power Corporation at one of its park entrance
kiosks. The fuel cell provides electricity as well as
heat for the kiosk.
Nearly all installed propane powered fuel cells are small (<10 kW). The limitation on the size of
installed propane fuel cells appears to relate to two issues; 1) the technically difficult problem of
building a propane powered hydrogen reformer and 2) lack of market demand for the larger
solutions where natural gas dominates.
The Propane Education Council is the main entity funding and tracking the development of propane
fuel cells. Currently it has solicitation for a detailed study of propane fuel cell installations and
results out for bid. Upon completion of this study, a realistic timeframe and review of the prospects
for a propane fuel cell system in Gustavus should become clearer.
1. Fuel Cell Technology Review
This section presents a brief review of the fuel cell technologies that may be appropriate for use in
Gustavus in the near future.
Proton Exchange Membrane (PEMFC): Smaller, easier to manufacture and operate at lower
temperatures, but more sensitive to fuel impurities. PEMFC’s are the primary candidates for
automobiles. Stack and cell endurance have presented some problems, resulting in shorter than
expected useful lifetimes.
Phosphoric Acid Fuel Cell (PAFC): Most mature of fuel cell technologies, large stationary PAFC’s
up to 250 kW are commercially available and installed at over 200 sites around the world. PAFC’s
can tolerate more impure fuel than other types of fuel cells and are highly efficient when used for
cogeneration, but are larger and generate lower current and power relative to other technologies. In
addition PAFC’s require expensive platinum as a catalyst.
Solid Oxide Fuel Cell (SOFC): A promising technology for large, high power applications. Larger,
more difficult to manufacture and operate at higher temperatures (up to 1,000 º C). Demonstration
units have produced up to 220 kW and several companies have designs close to commercialization.
25
Molten Carbonate Fuel Cell (MCFC): also highly efficient and operate at high temperatures (1,200 º
C). 10 kW to 2 MW demonstration models have operated on several different types of fuel,
including propane. High temperatures, however, enhance corrosion and the breakdown of cell
components.
2. Fuel Cell Manufacturers
This section briefly describes the state of some fuel cell manufactures producing models that may
be appropriate for Gustavus.
United Technology Company (UTC) has sold over 250 200kW PAFC’s (Model PC25) at costs
around $4,500/kW. Most run on natural gas, but many use methane from biomass, and at least one,
in Guangzhou, China, uses propane. The lifetime of the units has only reached five years however,
typical of PAFCs. UTC is now focusing on its 150 kW PEM models, which, while somewhat less
efficient, are also less costly. UTC also has large SOFC models in long term development.
Fuel Cell Energy: has commercialized a 250 kW MCFC and shipped over 25 units in 2003 (see cost
example below).
Fuel Cell Technologies, H Power and Avista Labs have each installed small (5 kW) fuel cells
running on propane in commercial settings, including Yosemite, Yellowstone, Kehoe Bay and
Department of Defense sites. (Fuel Cells 2000, 2002)
Plug Power recently formed a joint venture with GE in order to sell, install and service the Plug
Power fuel cell running on natural gas or propane. When available, the initial products targeted are
sized in the several kilowatt range and are intended for use by individual households and small
businesses. The venture has stated an intention to build larger commercial scale fuel cell systems.
3. Case Study for Gustavus
We contacted Fuel Cell Energy regarding their 250kW MCFC (model DCF 300A) which utilizes
natural gas. Based upon the specifications and our discussions with the firm the unit would
consume 7,260 BTU per kWh produced (commonly referred to as “heat rate”). At $0.95 per
gallon6, the propane fuel will cost 8.3cents per kWh.
Assuming a cost of $4,500/kWh ($1,125,000) the added capital
cost of the project is likely to equate to 8.0 cents per kWh, for a
total cost of 16.3 cents per kWh7.
In addition to this 16.3-cent cost, we estimate the marginal cost
of moving from a natural gas based reformer to a propane
reformer to be 1 to 2 cents. This figure is provided as an
estimate as we could not locate a commercially available
propane reformer system of the appropriate scale.
6 See Preliminary Draft Environmental Assessment, Sub Appendix A, Base Case Assumptions
7 Using manufacturers assumptions regarding availability, maintenance cost, stack degradation and replacement and
financing term, interest rate and developer’s 15% margin
26
The final cost of the fuel cell system, at 20.4 cents is competitive with either the existing diesel
generation or the proposed Falls Creek Hydro project. This cost does not include any federal or
state rebates that may be available.
4. Hydrogen Future
A future option for reducing the cost of a fuel cell at Gustavus may come from wind farms currently
being planned in the Prince Rupert, BC area. Several developers have proposed developing
significant onshore of offshore wind resources in the range of several hundred megawatts each.
Assuming that some of these developers are successful in building out these projects, it is likely that
at certain times excess electricity will be available due to transmission constraints. It may be
possible for a business to be developed that would generate hydrogen with the excess electricity,
transport and sell it to rural communities for use in fuel cell applications. More information on
companies proposing to develop wind farms in the Northern BC area can be obtained from BC
Land and Water.
C. Southeast Alaska Intertie (Submarine Cable)
Conclusion: Despite significant capital requirements, there continues to be strong interested
pursuing the proposed Southeast Intertie, which presents a possible alternative to the Falls Creek
Project.
A preliminary draft report on connecting Gustavus to Hoonah via a submarine cable as part of the
proposed Southeast Alaska Intertie was completed in July 2003 and should be available publicly in
the Fall of 2003. Estimated construction costs for the Hoonah Gustavus leg are $23 million, with an
annual operating cost of around $500,000 (including O&M, A&G and contingency funds, but no
recovery of capital costs). These costs include a connection to Glacier Bay National Park, but not
Excursion Inlet. Federal legislation, which has approved, but not yet funded, the Southeast Intertie,
requires 20 percent matching contribution. It is anticipated that at least a portion of the matching
funds would be contributed by the State of Alaska.
The economics of such a project present a formidable challenge. However there continues to be
significant interest in linking rural towns in Southeast Alaska to hydro facilities via submarine
cables in order to utilize excess capacity and reduce diesel generation.
D. Energy Efficiency
Conclusion: low cost savings of 20-30 percent are possible and could be used in combination with
alternatives or to defer capital investment in new facilities, resulting in net savings for Gustavus.
Gustavus has a population of 421 permanent residents, with nearly double that population during
the summer tourist season. The town consists of 345 housing units 146 of which are vacant some
portion of the year (2000 census).
Peak loads of approximately 300 kW occur both in the winter, for lighting and heating loads, and in
the summer, during the tourist season. Peak loads typically occur in the evening around dinnertime.
(Preliminary Draft Environmental Assessment, Appendix A HDR Study of Generating
Alternatives). 2002 annual generation was 1,400 MWh.
27
The Preliminary Draft EA states that conservation was not considered as an alternative because
“GEC is expected to have adequate capacity throughout the study period with only the existing
resources. Therefore, load management and energy conservation could provide savings to the
consumer but would increase GEC’s per-unit cost of energy.” (p. 23). This assertion sidesteps
many strong arguments for supporting efficiency programs, programs that are routinely
implemented by utilities throughout the US despite the fact that they reduce energy sales and
increase the capital cost per kWh that must be recovered. In the case of Gustavus, increased energy
efficiency will reduce the total PCE subsidy ($0.2235/kWh) paid by the AEA. A 20 percent
reduction in annual energy consumption would reduce the PCE subsidy by approximately $62,000
each year (based on 1,400 MWh used in 2002). Utilities commonly use efficiency programs to
defer investments in new facilities, delaying capital expenditures that would increase rates even
more. With a weighted cost of capital of 10 percent and an inflation rate of 3 percent, deferring a
capital investment of $4.1 million for five years results in a net savings of $1.1 million.
The Alaska Energy Authority (AEA) and Rural Alaskans Conserve Energy (RACE) and Rebuild
America have performed several studies and energy audits for small rural Alaskan towns, including,
Kake, Craig and Tanakee Springs. The Alaska Energy Authority sponsored energy audits for the
Gustavus community buildings and the Gustavus School that were performed by Heat Loss
Analysis in June 2001. In the library, fire hall and school energy efficient lighting in the form of
florescent T8 lamps with electronic ballasts were already in place. However, the study found that
older lights in the community building and the clinic could be replaced with more efficient fixtures.
A combination of measures resulted in calculated savings of over 4,000 kWh per year for these two
buildings. These findings, as well as the success of efficiency measures taken in other Southeast
Alaska towns suggest that an energy savings of 20-30 percent is certainly possible in Gustavus.
While efficiency cannot eliminate the need for new generation, it can defer capital investment and
result in net savings, the arguments made by Gustavus Energy notwithstanding.
1. Tenakee Springs
In the Summer of 2002, the Alaska Energy Authority led an
energy efficiency retrofit effort in Tenakee Springs, a small
town located on the east side of Chichagof Island in Southeast
Alaska. Most of the structures in the village were built in the
early 1900s and have been well maintained, but many were in
need of new lighting and thermal upgrades. Figure 12 shows
the measures implemented in Tenakee Springs and the
resulting savings. Light Bulbs Arrive at Tenakee Springs
28
Figure 12
Energy Efficiency Measures Implemented in Tenakee Springs and Resulting Savings
Location No. Item Cost
Annual
Savings
Simple
Payback
(years)
Savings
(kW)
Savings
(kWh)
Commercial
Mercantile 10 Light Fixtures $260 $204 1.3 0.49 815
Post Office 6 Light Fixtures 316 125 2.5 0.3 499
School 166 Light Fixtures 18,062 1,573 11.5 4.58 6,290
Clinic 6 Light Fixtures 811 128 6.3 0.66 512
Community Hall 50 Light Fixtures 2,630 1,456 1.8 2.5 4,160
Residential
26 Residences 85 Light Fixtures 6,150 2,964 2.1 4.8 8,469
12 Refrigerators 6,228 2,313 2.7 2.4 9,250
Total $34,457 $8,763 3.9 16 29,996
Improvements were made in 26 homes, or approximately one quarter of the residences in Tenakee
Springs. Overall the efficiency measures resulted in an annual savings of nearly 30,000 kWh and
$8,763. This was achieved primarily though replacing lights with more efficient fluorescent
fixtures. In addition, 12 older refrigerators were also replaced. The average simple payback period
was less than four years and in most cases less than three years. These payback periods were
calculated with electric rates of $0.25/kWh (After PCE) which are similar to Gustavus Electric rates
after the PCE of $0.28/kWh.
2. Efficiency Measures
In residential homes, installing energy efficient compact fluorescent light bulbs (CFL’s) is typically
the most practical and economic option for reducing electricity use. CFL’s are 75 percent more
efficient than incandescent bulbs and last ten times as long. Technological advances have long
since overcome initial complaints associated with compact florescent lights (such as flicker, delayed
start up and noise). A wide range of CFL’s are now available that are dimmable, silent, without
flicker and without start up delays. CFL’s can also produce higher quality light as compared to
incandescent bulbs.
Installing three CFL’s in just one quarter of Gustavus’s approximately 200 full-time and 150 part-
time dwellings would save approximately 23,000 kWh per year. Because peak generation occurs
during the evening hours, when most of these lights are likely to be in use, peak demand could be
reduced by up to 20 kW. This would reduce PCE payments by over $5,000 per year and save
$3,000 in fuel costs (of about $0.13/kWh). The total savings to the residential customer from CFL’s
would pay for their installation in approximately two years.
As described above, it is also likely that more efficient lighting could be installed in several
commercial and municipal buildings that have not already installed fluorescent T8 lights with
electronic ballasts. Timers, motion sensors and photo-electric sensors can also significantly reduce
lighting demand. In addition replacing emergency and exit lighting with LED signs also saves
about 300 kW per year per fixture. The 2001 audit found that two of the five buildings examined
29
could benefit from these types of measures, with savings of over 4,000 kWh per year. If similar
savings could be found in the fifteen or so commercial and community facilities that were not
included in the study, energy demand could be reduced by 12,000 kWh per year.
In Tenakee Springs, refrigerators were replaced in 12 of the 90 households (13 percent) at a total
cost of $6,200, resulting in a savings of 9,251 kWh. The new refrigerators cost approximately $500
a piece, depending on size, and saved on average 771 kWh per year. A similar effort in Gustavus
would replace 45 refrigerators, cost around $23,000 and save over 34,000 kWh a year.
Water heaters might present additional potential savings. Most, if not all of the water heaters in
Gustavus use oil. In addition to being more efficient given the high price of electricity, oil water
heaters are far more economical. However, to the extent any homes have electric water heaters,
replacing them with oil water heaters would save approximately 4,500 kWh per year per heater.
30
IV. Other Generation Technologies Considered
A. Wind
Conclusion: Wind does not represent an economically viable option due to lack of sufficient wind
in the area as well as its tendency to be intermittent on a seasonal basis.
Background: Large wind turbines (1.5 megawatt and above) are now
cost competitive with least cost fossil fuel generation in areas with
consistent strong winds (6-10 meters per second). In the best sites,
large wind turbines can generate power at 3.5 cents or below. Since
wind power is a cube of wind speed, turbine output and the generated
cost of energy is dramatically impacted by wind speed.
The Alaska Energy Authority and the Alaska Industrial Development
and Export Authority funded an analysis titled “Initiatives Aimed at
Improving Rural Energy Efficiency and Reliability” in December of
2002. This report included an analysis of wind power in rural villages
and rank ordered the top 31 communities most likely to be able to cost
effectively capitalize on their wind resource. Gustavus was not
included in this list.
Our review of these analyses was supplemented by conversations with the owner of the Bear Track
Inn in Gustavus, Mike Olmey, who referred us to a Lee Baker, also a Gustavus resident. Lee has
installed and operated windmills in the area for over ten years. Our discussions with Mike and Lee
confirm the conclusions reached in the HDR analysis regarding low wind speed in Gustavus.
Specifically, Gustavus is in a low plain with no nearby hills upon which turbines could be mounted
to catch higher-level winds. Lee also mentioned that the wind in the area is intermittent on a yearly
basis; that is some years there is wind and some years there is not. His conclusion was that upper
level weather patterns, of global long-term nature, led to this intermittent wind pattern.
B. Biomass
Conclusion: While a sufficient quantity of wood waste exists just across the Icy Strait, wood
waste is not a viable option for electrical production due to future availability concerns, shipping
and handling costs as well as a lack of proven small-scale biomass to electricity conversion
devices.
Background: Wood wastes from lumber operations represent a substantial waste to energy
conversion opportunity for Southeast Alaska. Lumber operations generally dispose of wood waste
through burning with no associated energy production. Technologies exist to convert these
feedstocks through:
Gasification and utilization of the gas in an engine or turbine to turn a generator and make
electricity,
Direct combustion for powering a steam boiler and associated turbine/genset,
Direct combustion in conjunction with a hot-air engine, generally a Stirling cycle.
31
In order to determine the viability of utilizing wood waste, we reviewed the availability, cost and
usability of area feedstock. Using these assumptions, we further analyzed the feasibility and costs
across the three energy conversion options above.
The report “Southeast Alaska Biomass-to-Ethanol Project
Feedstock Supply Plan”, by TSS Consultants, June 20, 2000,
identified Whitestone Southeast Logging in Hoohan, Alaska,
just across the Icy Strait from Gustavus as having excess
lumber yard waste that is currently being disposed of by
burning. The estimate was for 3,125 bone dry tons (BDT) of
sawdust and bark and 1,000 BDT of slabs, butt and long ends
available each year.
We contacted Whitestone Southeast Logging to check on the
current status of their operations and spoke with Dave Owens, manager. Dave indicated that the
logging operations are still in place, but that the future is uncertain. They are mostly taking logs
now from private lands rather than from their historic source, the Tongass National Forest. When
discussing the potential to use the wood waste from the operations for energy production in
Gustavus, Dave expressed the following concerns:
1. Gustavus does not have a good port to the Icy Strait.
The coast is a long beach with no place for a port where
the wood could be unloaded. Currently, goods are
shipped up the Salmon River into town via barges of
various sizes. The barge captain Whitestone Logging
uses received complaints in the past from Gustavus
residents regarding an incident where the barge ran
aground. This was using a large barge of the type
necessary to haul wood waste. The captain has
indicated that he refuses to take the large barge back up
river and into town.
2. The cost of handling small pieces of wood waste would be very high. There are currently no
facilities for chipping, drying, transporting or storing the materials at either Whitestone or Gustavus.
An example of a barge loading facility of the type needed, from the Viking mill at Klawok, AK, is
pictured above.
3. Environmental considerations. Dave recommended I review the history of the co-gen steam plant
at a sawmill in Haines. He indicated that the wood fired facility was shut down due to
environmental concerns and that a wood fired solution was unlikely to be acceptable for Gustavus.
We called the town of Haines and confirmed that the power is now supplied by hydro and that no
wood fired electricity is generated. We were not able to confirm the reason for the plant being shut
down.
We note that Dave Owens also indicated that he has worked on the Falls Creek Hydro project and
believes that it is the best solution for the energy needs of Gustavus.
32
Assuming the transport and handling issues could be resolved in a cost effective manner, options for
such small-scale energy conversion do exist, but they are not yet widely proven or cost effective at
this time. A brief review of these options is presented below:
1. Bio-gasification
Community Power Corporation had developed a bio-gasification technology that consumes 1.5 kg
of wood waste per kilowatt-hour of electricity produced. Gustavus consumes approximately 2,000
MWh of electricity per year. Using this device, approximately 3300 bone dry tons of wood would
be required. Whitestone logging is noted to have approximately 3,125 bone dry tons (BDT) of
sawdust and bark and 1,000 BDT of slabs, butt and long ends available each year.
2. Direct Combustion with Steam Turbine
Our analysis of the available products for direct combustion of wood waste, generally through
fluidized bed combustors indicated that no technologies are available in the sub 5-megawatt range.
OSHA rules require a full time operator when high-pressure steam is utilized. Therefore, the
economics of steam turbine generation dictate that a certain economy of scale must be reached
before the project is economically viable.
3. Direct Combustion with Hot Air Engine
Hot air engines work on a similar principal as the classic James
Watt steam engine; only they use low-pressure air as the
expansion fluid rather than steam, and therefore do not require an
operator. The most notable of the hot air engine designs are the
Stirling and Ericsson engines. Matched to a biomass furnace
providing sufficient heat output, a hot air engine mated to a
generator could provide significant electrical generation.
Currently several manufacturers of Stirling engines are nearing
commercial availability. The most notable of these is STM Power, owned by Detroit Edison. A
single STM power module provides 55kw of power and consumes 0.5 kg of wood waste per kWh
of electricity produced8.
C. Biodiesel/Fish Oil
Conclusion: Not an economically viable option due to the distance between feedstock supplies
and Gustavus.
Background: Conventional diesel engines, such at the ones employed by Gustavus Electric, can
generally utilize high quality biodiesel with little or minor modification. In addition, work has
been done to successfully utilize fish oil in a blend with conventional diesel. Should a stable source
of biodiesel or fish oil be available or be developed in the region, the existing diesel generation
units might be capable of utilizing the fuel, potentially mitigating fuel price risk, as well as reducing
particulate emissions. 100th Meridian undertook research to identify the availability of biodiesel,
biodiesel feedstocks or fish oil within the region. Biodiesel is generally made from high fat waste
8 Assuming 160 therms per BDT wood and 12,000 BTU per kwh
33
products such as animal renderings, from high oil content agricultural crops such as soybeans or
from frying oil recycled from restaurants.
We contacted the Alaska Energy Authority, spoke with local residents and contacted a variety of
commercial entities regarding feedstock availability. Our findings indicate that the agricultural,
animal rendering and restaurant based feedstocks necessary for biodiesel production do not exist in
the region in quantities sufficient to build a cost effective production facility. Specifically, no high
oil content agricultural crops are grown in the region and no slaughterhouses are nearby.
With respect to fish oil, we were provided with a report entitled “Demonstrating the use of Fish Oil
as a Fuel in a Large Stationary Diesel Engine”, J.A. Steigers, 2002. This report analyzed the
potential for burning fish oil directly, without conversion of the oil into biodiesel. The fish oil is a
byproduct of Pollack processing both at on-shore facilities and in floating processing centers.
The report and our conversations with its author, John Steigers
at Steigers Corporation indicates that fish oil was burned in a
variety of blends with conventional diesel in Fairbanks Morse
3160 and 3960 horsepower two stroke diesel engines.
Steigers Corporation is currently undertaking similar research
utilizing 4 stroke diesel engines, the type utilized currently by
Gustavus Electric. The results of the report conclude that with
some engine modification, fish oil in a blend up to 50 percent
with #2 diesel, could be burned directly in these engines.
Emissions results indicated a decrease in particulate emission
of up to 60 percent, decrease in sulphur dioxide of up to 78
percent and decrease in carbon dioxide of up to 33 percent. An increase in nitrous oxide of up to 8
percent was also observed. The report concluded that the emissions reductions were essentially
offset by the nitrious oxide emissions and emissions benefits should be viewed in the context of the
local relative to the emissions component.
Most fish processing facilities internally utilize the waste fish oil for boiler fuel. This leaves no
excess fish oil available. However, large facilities in the Aleutian chain such as two in a thirty-five
mile radius of Dutch Harbor have excess fish oil that they sell to the market for a variety of uses
including export. The primary feedstock identified by the report was the UniSea processing facility
on Amaknak Island. Another processing facility approximately thirty miles away was also
presented as having excess fish oil. A third in Kodiak Alaska was also mentioned as a potential
feedstock supplier. The Dutch Harbor community is approximately 1000 miles from Gustavus and
Kodiak over 500 miles. These distances are far too large to allow for cost efficient transport of the
fuel to Gustavus. We were unable to locate fish processing facilities nearer to Gustavus that have
excess fish oil.
Floating fish processing facilities (“mother ships”) also have the potential of generating large
amounts of fish oil as they currently do not extract nearly as much oil from fish processing as do
land based processors. John Steiger’s opinion was that the economics of additional fish oil
generation did not make sense for these floating facilities and that absent some regulatory impetus,
their potential as a fish oil supply source was limited.
34
D. Higher Efficiency Diesels
Conclusion: Installing a higher efficiency diesel engine and potentially configuring it to load
follow may be a means of reducing cost and fuel consumption, but a detailed operational analysis
is required before a definitive conclusion can be drawn.
Gustavus Electric operates 4 diesel generation units. Currently, Gustavus units are dispatched as
needed. Once dispatched, the machines are run unattended and at a constant speed. The most
efficient of these units is dispatched first. It is a 250 kW Cummings diesel with approximately
45,000 hours on it and produces 13.75 KWh per gallon of fuel under full load, equal to just over 10
cents per Kilowatt hour9. Other older less efficient (12 kWh/g and below) units are dispatched on
top of this first unit on an as needed basis.
To evaluate the impact of newer, more efficient diesel engines, we relied upon the Rural Alaska
Energy Plan: Draft Diesel Efficiency Plan, prepared for the Alaska Energy Authority, December
2002. The report noted that fuel cost is up to 85 percent of generation cost in a diesel system, and
therefore savings of as little as 5 percent may justify the cost of upgrades. Two types of
retrofits/upgrades of potential applicability were highlighted in the report. The first is switchgear &
controls to allow the generators to load follow. The second was replacing the gensets with newer,
more efficient technology.
Evaluation of the benefits of switchgear & controls requires analysis of the impact on maintenance
and reliability, which is outside the scope of this report. It is noted that while an industry average
savings of 5 percent was standard, each situation varies and in many cases these upgrades were not
cost justified based upon the savings. Therefore, without a detailed study, a proper analysis cannot
be conducted. It is noted in the report that often the best time to install load following technology is
in conjunction with a genset upgrade.
The report went on to identify two gensets that provide high efficiency, with one operating across a
relatively similar load profiles as in Gustavus (Detroit Diesel Series 60).
9 Using $1.41/gallon diesel
35
Figure 13
Figure 13 illustrates the KWh per gallon of the Detroit Diesel (DD) machine, a larger Caterpillar
machine and the 13.75KWh output of the existing Gustavus Cummings machine. The DD
machine’s highest efficiency is 16 KWh per gallon and at the Gustavus minimum base load
(~150KW) it achieves well over 14 KWh per gallon. In order to calculate potential fuel saving from
this new genset, we assume the DD machine is run unattended at a constant 250KW output, the
same as the existing Cummings genset. At this output, the DD machine generates 16KWh per
gallon, well above the 13.75 KWh per gallon noted in the Project Preliminary Draft EA for the
existing Cummings engine.
Figure 14
Diesel Genset Fuel Cost
$0.080
$0.085
$0.090
$0.095
$0.100
$0.105
Per Kilowatt HourDD @ 250KW Load
Commings @ 250KW
Load
36
This represents a 16.3 percent increase in efficiency and shifts the cost of fuel from 10.3 cents to 8.8
cents per KWh using $1.41/g diesel. Assuming a 95 percent availability factor for both machines
and equal maintenance costs over time, the move to the DD machine would save $30,000 per year
in fuel which could be applied to amortization of the capital investment.
Additional factors that may further reduce fuel consumption and generation cost include:
1. Consideration of the broader power range of the DD machine, whereby it can offset dispatch
of the even less efficient existing Gustavus machines in the 250KW to 350KW range.
Currently machines with efficiency below 12KWh per gallon are dispatched when load
requires additional generation.
2. The addition of load following technology in conjunction with the genset upgrade whereby
the DD machine would adjust its output to match the load requirements and thereby reduce
fuel consumption.
In summary, it appears that technology exists that would, at a minimum, reduce Gustavus’ diesel
fuel consumption by 16 percent. Whether this savings is sufficient to warrant replacement of the
existing technology and whether additional load following technology might be appropriate, will
require access and analysis of detailed data relating to the operation and cost of Gustavus’ existing
gensets.
Further Note: We reviewed with Jed Davis of the Glacier Bay National Park Service the recent
installation of new generators to serve its load. He noted that the fuel cost per kWh produced was
averaging in the 12 cent range and that cost per KWh when capital costs are included was around 20
cents.
37
E. Micro Hydro
Conclusion: Small and Micro-hydro technologies may be appropriate for individual households,
but do not appear viable as a larger generation resource for the town of Gustavus.
The Good and Salmon Rivers flow through the town
of Gustavus but have relatively low gradients. While
there are high volume/low head hydro technologies,
they do not appear to be viable for these rivers, as
both the flows and the gradients are too low. In river
turbine/propeller technologies have been proposed for
larger rivers, including a proposed project on the
Yukon River near Eagle (UEK technologies). Smaller
designs (1 kW or less) are available and may be
suitable for individual homes near the Good and
Salmon Rivers. Propeller designs are, however, the
least efficient of the small and micro-hydro
technologies. Smaller (1 kW) reaction turbines
(designed for high volume/low head) require at least
two and generally five or more feet of drop, which in the case of the Good and Salmon rivers,
would require lengthy diversion structures.
1 kW Reaction Turbine
38
V. Conclusion
We are sympathetic to the desire to reduce Gustavus’s reliance on diesel generation. However, the
proposed Falls Creek Hydroelectric Project is not a sound or economically viable means of doing
so. The project will irreversibly alter a unique resource inside a national park and commit Gustavus
to high cost generation that will limit its ability to benefit from technological advances in other
promising technologies in the future. The project will generate power at costs higher, not lower,
than existing diesel generation and increase, rather than reduce Gustavus Electric’s rates. The
specific burden that the Glacier Bay Boundary Adjustment Act places upon this project to prove
economic viability and sound financing has not been met.
Energy efficiency has been proven as an effective means of reducing energy demand in other
Southeast Alaska communities and can defer the need for new investment in capital intensive
generating resources. While Gustavus Electric expressed concern that conservation will only
increase electric rates, utilities throughout the US have implemented efficiency programs with
benefits for both the consumer and the utility. The community may want to initiate discussions with
the Regulatory Commission of Alaska and the Alaska Energy Authority regarding how efficiency
programs could be implemented and funded in Gustavus.
Fuel cells, tidal generation and the Southeast Intertie are all potential alternatives that may become
economically feasible well before electric demand in Gustavus nears or exceeds existing generating
capacity. While the future of these technologies is far from certain, significant investments and
advances are being made and many are optimistic. Given the lack of urgent need for new
generation in Gustavus and the poor economics of the proposed Falls Creek project, it would be
prudent for Gustavus to allow several years for these alternatives to develop before committing
significant capital to the Falls Creek Project.
1
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2
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