HomeMy WebLinkAboutAPA358Power Project Development and
Financing in Alaska
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Alaska State Legislature
January 1983
House Research Agency Report 82·C
The House Research Agency is the permanent, non-partisan research
support arm of the Alaska State House of Representatives. The
agency performs research at the request of legislators. A biparti-
san governing committee composed of the House Speaker and Minority
Leader and the ranking House member of the Legislative Council
(i.e., either chair or vice-chair), oversees the agency's work.
While the legislature is in session, most research is of a discrete
scope. During the interims between legislative sessions, projects
of larger scope are undertaken.
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POW.E~ PROJEC T! DEVEl0P.ME~¥
AND FINANCING IN AIL~SKA
PREPARED FOR
n ~~biFIC
NORTHWEST
INC. --~~l'lr1
813 S.W . ALDER • SUITE 500
PORTLAND, OREGON 97205
(503) 223 -9147
OF THE AUTHORITY'S RATE STRUCTURE ••..••
Revenue Stability .............................. .
Conservation Considerations ..••.•.•••••.•.•.••..
Policy and Equity Considerations •••.••.•.••.•.•.
ALTERNATIVES FOR LEGISLATIVE DIRECTIVES GOVERNING
THE AUTHORITY'S RATE STRUCTURE •••••.••.••••••••.•• 4-24
Rate Structure and Rate Level ••.•••••••••••••••• 4~24
POWER SALES CONTRACTS •••••••••.••••.•.•••••••••••• 4-31
REVIEW AND ASSESSMENT OF STATE FUNDING
OF POWER PROJECTS
INTRODUCTION..... . . . . . . . . • . . . • • . . . . . . • . • • . . . . . • • . . 5-l
ENERGY PROGRAM FOR ALASKA............ . • • • . • • . . • . . • 5-2
PROPOSED ENERGY RESOURCE FUND •..•.•••.••••••••.•.. 5-2
DISCUSSION OF PROPOSED ENERGY FUND •••.•••.•••.••.. 5-4
OTHER ALTERNATIVES.. . . • • • • • • • . • • . • • . • • • • • • . • . • • • • . 5-7
REVIEW AND ASSESSMENT OF DEBT FINANCING
FOR POWER PROJECTS
STATUTORY DIRECTIVES RELATED TO
6-1
DEBT FINANCING. • • • • • . • • • • • • • . • • . • • • • . . • • . • • • • . . • . . 6 -2
Bonds of the Authority •••••.•....••.•••••••.•••. 6-2
Trust Indentures and Trust Agreements •••••••.... 6-3
General Financial Provisions .................... 6-4
INTERIM DEBT FINANCING ..•••••••••.•.••.•••.••.•••. 6-4
Authority Interim Debt Financing Program ••.•••.• 6-4
Authority Interim Debt Financing Policy •••••..•• 6-7
Assessment of the Authority's Interim
Debt Financing Program and Policy ••.•••.•••..... 6-7
LONG TERM DEBT FINANCING.......................... 6-10
Assessment of "Plan of Finance for Alaska
Power Authority Projects" •.•••••.•...••••••••..• 6-11
REVIEW AND ASSESSMENT OF ALTERNATIVES FOR
DISPOSITION OF PROJECTS UPON COMPLETION
OWNERSHIP OF COMPLETED PROJECTS ••...•.••.••••.••.. 7-1
PROJECT OPERATION AND MAINTENANCE •••.••.•••••••••• -7-2
General Utility Practice ••.••••.••••.•••.••..••. 7-2
Alternatives for Operation and Maintenance
of Authority Projects ••.•..••••..•••.••••••. ! ...
Operation and Maintenance of Other ~ -·
State Funded Projects ••••••••.•......••••.•.••.•
2-A
2-B
3-A
3-B
,
3-C
4-A
I N D E X 0 F A P P E N D I X E S
ALASKA UTILITIES
SUHMARY OF ENERGY PROGRAMS WITHIN ALASKA
CASE ANALYSIS, TYEE LAKE HYDROELECTRIC PROJECT
ALTERNATIVE METHODS OF ANALYZING REGIONAL POWER
SUPPLY ALTERNATIVES
' REVIEW OF POWER MARKET &~EA ANALYSIS
1982 PROPOSED CHANGES IN RATE STATUTES
5-A PROPOSED ENERGY RESOURCE FUND
6-A INTERIM FINANCING FOR ALASKA POWER
AUTHORITY PROJECTS
6 -B PLAN OF FINANCE FOR ALASKA POWER
AUTHORITY PROJECTS
Page
Number
2-27
2-28
3-51
3-63
3-68
4-33
IN D.E X 0 F A B BREVI AT I 0 N S
ALASKA POWER ADMINISTRATION (APA)
ALASKA POWER AUTHORITY (AUTHORITY)
ALASKA PUBLIC UTILITIES COMMISSION (APUC)
DEPARTMENT OF COMMERCE AND ECONOHIC DEVELOPMENT (DCED)
DEPARTMENT OF ENERGY (DOE)
DIVISION OF BUDGET AND MANAGEMENT (DBM)
(Renamed OFFICE OF MANAGEMENT AND BUDGET (OMB))
DIVISION OF ENERGY AND POWER DEVELOPMENT (DEPD)
DIVISION OF POLICY DEVELOPMENT AND PLANNING (DPDP)
ENERG Y PROGRAM FOR ALAS KA (ENERGY PROGRN1)
FEDERAL ENERGY REGULATORY COMMISSION (PERC)
FEDERAL FINANCING BANK (FFB)
FEDERAL POWER MARKETING AGENCIES (FPMA)
PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978 (PURPA)
RURAL ELECTRIFICATION ADMINISTRATION (REA)
TAX EXEMPT NOTE RATE (TENR)
U.S. ARMY CORPS OF ENGINEERS (CORPS)
VARIABLE RATE DEMAND NOTES (notes)
SECTION I
INTRODUCTION AND SUMMARY
As was anticipated, the work involved in this study presented
a challenging assignment. The scope ot the study covered essen-
tially all of the activities involved in Alaska's Power Project
Development Program. In addition, a number of related issues have
been addressed.
One of the most challenging aspects of the work was the fact
that we were dealing with what might best be termed a "moving
train". During the course of the work a number of important ele-
ments of the Program were under review and, in some cases, actually
revised by the Alaska Power ·Authority and other agencies. To the
extent possible we have recognized these changes but there are
undoubtedly some instances where we have not been able to do this.
Our work was undertaken within the framework of six separate
tasks. These were:
_, ..
0 Alaska Power Supply
0 Development Program of Alaska's Power Project
0 Wholesale Power Rate Structure
0 State Funding Alternatives for Power Projects
0 Debt Financing Alternatives for Power Projects
0 Alternatives for Disposition of Projects Upon Completion
This section of the report provides a summary of the results
of our work. To accomodate the reader with limited time, this
material provides only our major observations and alternatives to
present practices and procedures. The balance of the report
provides a detailed discussion of the work under each of the
tasks listed above.
ALASKA POWER SUPPLY
A number of organizations are involved in energy research,
development and management activities directly and indirectly
related to power supply in Alaska. Nearly every agency or
department of state, local and federal government is involved to
some degree in energy related pursuits, although these are not
all related to power supply. Section 2 of the report provides an
overview of the institutions and legislative directives relating
to Alaska power supply.
General Observations
Our general observations of institutions and legislative
directives relating to Alaska power supply are as follows:
0
0
0
0
Legislative directives relating to Alaska power supply
have evolved over a period from the early l960 1 s.
Significant changes have been made, almost on an annual
basis, beginning in the mid 1970's.
The key agencies involved in Alaska power supply, in
addition to the State's utilities are:
Alaska Public Utilities Commission (APUC)
Division of Energy and Power Development of the
Department of Commerce and Economic Development (DEPD)
Alaska Power Authority (Authority)
Other agencies and the Legislature itself are involved
in the funding of power supply facilities independent
of the Energy Program for Alaska and there exists a
multitude of. programs relating to electrical energy
under several agencies.
There are important ar~as of Alaska power supply
development where there is overlapping responsibility.
Particular examples of this are in the areas of planning,
conservation, and renewable resources.
Alternatives for Consideration
It may be time to stabilize existing responsibilities and
programs to allow a maturing process in activities related to
power supply. However, consideration might be ~iven to some
1-2
..
consolidation of similar programs and clearer definitions of
responsibility to take advantage of the expertise and experience
of particular agencies. The objective of such an effort would be
to minimize overlap and duplicative responsibilities and programs.
An example of an alternative to accomplish this would be
centralizing responsibilities, at the State level, for power
supply activities with the APUC, the DEPD, and the Authority.
The APUC might well be given the added responsibility for review
and coordination of utility service area forecasts. The DEPD
might assume full responsibility for the planning, assessment,
and implementation of conservation programs and for the continu-
ing assessment of renewable and alternative energy options. The
Authority then, would be responsible for power suppy planning,
reconnaissance studies, feasibility studies, and project financ-
ing and development. These activities would utilize the work of
the APUC on load forecasting, as well as the work of the DEPD on
conservation and renewable resources.
ALASKA POWER PROJECT DEVELOPMENT PROGRAM
The work involved in our review and assessment of the Alaska
Power supply Development Program was the primary focus of the
study. The scope of this work included:
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0
0
Power supply planning
Reconnaissance and feasibility studies leading to
project selection
Project authorization process
General Observations
The following are general observations with respect to the
power supply development program:
0 The Authority has inherited a variety of studies and
data relating to all aspects of power supply as well as
individual projects that were in one stage or another
of development. The power supply planning process is
an evolving one and, although the Authority has and
continues to implement improvements, it is not yet
mature.
0
0
0
Power supply planning areas have not been well
defined beyond the Railbelt region.
Load forecasting has been undertaken by individual
utilities as well as several State agencies.
However, the credibility of load forecasts
continues to be questioned and there has not been
an integration of load forecasting and power
supply planning. The DEPD's Long Term Energy Plan
includes a section relating to electrical energy,
but it does not constitute a power supply plan, even
at the State level. For the most part, power supply
plans for individual areas of the State have not
been developed and periodically updated.
The Authority has made significant improvements in their
approach to and the methodology utilized in reconnaissance
studies. However, with the introduction of a more disci-
plined power supply planning process additional improve-
ments in the reconnaissance level studies are required.
The Authority has also made significant improvements in
their approach to feasibility studies. The Office of
Management and Budget (OMB) has provided a number of
recommendations for improvements in the feasibility
study process in addition to their oversight and review
role of completed feasibility studies. However, there
continues to· be areas where further improvements in the
feasibility study phase of power supply development can
be made.
As the feasibility study provides an assessment of
"economic feasibility", the financial plan does essen-
tially the same thing with respect to "financial feasi-
bility". The Authority's work with their financial
advisors and bond counsel towards the end of developing
overall financial policies has laid a good foundation
for the development of financial plans This will be an
important element in the decision process for future
projects.
The project authorization process is unique in that the
Legislature is, in effect, the final decision maker,
with the concurrence of the Governor. This occurs
because of the significant financial participation of
the State in power project financing. The statutory
restrictions which limit the power of one legislature
to commit a future legislature, and the fact that the
budgetary process deals only with a single year while
power projects involve a commitment over an extended
period of design and construction are complicating
factors.
Alternatives for Consideration
It is emphasized that the power supply development process in
Alaska is evolving and that the Authority, with input from the OMB
'· l
and others, has made significant improvements in the several ele-
ments of that process. However, we believe that additional improve-
ments can and should be considered.
In this regard, alternatives offered for consideration are
summarized below:
0
0
0
0
0
The Authority, in consultation with other agencies inclu-
ding DEPD, APUC, and OMB, might define power supply plan-
ning areas consisting of population centers which are
presently interconnected or which might be interconnected
by transmission lines in the future. These areas would be
in addition to individual communities, primarily located
in bush areas, which would have to be dealt with on an
individual basis for power supply planning.
A formal assignment of responsibility for review and coor-
dination of utility load forecasts and the development of
independent load forecasts for power supply planning areas
as well as individual communities and villages might be
made. This responsibility could rest with the Authority
or with DEPD, but serious consideration should be given to
adding this responsibility to those of the APUC. A number
of reasons for this should be considered, including the
fact that load forecasts are an important part of other
APUC responsibilities, not the least of which is their
rate proceedings.
Once initial load forecasts were developed for the
various power supply planning areas, as well as
individual communities and villages, a procedure might
be developed that would provide for periodic review and
updating.
With defined power supply planning areas and compatible
load forecasts, the credibility of which would be enhanced
as a result of a formalized process discussed above,
accurate power supply requirements can be determined.
The reconnaissance level studies might then be focused on
providing a pool of resources for further study that would
be available to meet identified needs in the various areas
of the ·state. -Periodically, the reconnaissance level
studies would be updated to reflect technological advance--
ments in alternative and renewable resource technologies
as well. as changes in other factors.
0
0
Consideration should be given to incorporating other
economic evaluation methodologies, in addition to present
value life cycle cost analysis, in the assessment of
economic feasibility of alternative projects. It is sug-
gested that a comparison of the busbar costs of power from
alternative projects might be developed both on a constant
and current dollar basis. This methodology facilitates
development of sensitivity analyses with respect to the
several variables and assumptions involved in economic
analysis.
OMB should continue its oversight role in the review of
all aspects of the power supply planning and project
evaluation process. The Authority and OMB should cooper-
ate in the development of documentation for decision
makers which describes the entire power supply planning
process as well as requests for project authorization.
This documentation should be periodically updated and
reviewed with the appropriate committees of the Legisla-
ture and other State agencies.
WHOLESALE POWER RATE STRUCTURE
The Authority's wholesale power rate structure is based on
very explicit rate directives provided by the Legislature. There
has been a continuing evolution of legislative directives
relating to the Authority's rates beginning with the initial
legislation that created it.
General Observations
During the 1982 session, the Governor and Legislature undertook
a comprehensive review of the Authority's rate stxucture. Bills
reflecting the Governor's position, as well as a House committ~e
position, were considered and rejected. A compromise, HB 9, was
ultimately passed and signed by the Governor.
The changes in legislative direction concerning the Authority's
rate structure provided by HB 9 were significant. In place of the
uniform or "postage stamp" rate previously in effect, a project-
specific rate was established. HB 9 provided that there would be
some levelizing of the debt service costs between projects subject
to a cap.
The predominate feeling on the part of those directly
in~olved in the Authority's financing is that it is important that
legislative direction relating to rates be stabilized. However,
there are, relatively minor "housekeeping" and clarifying changes
that will be suggested to the Legislature this year.
Equally as important as the rates established by the Authority
is the language of power sales contracts covering the output of the
Authority's several projects. Our review of the most current draft
power sales contracts indicates that they are consistent with the
directives provided by HB 9 and that they do provide for adjustment
of rates in the face of unforeseen circumstances, for example,
abnormally low water conditions.
Alternatives for Consideration
Unless the language of HB 9 is interpreted to be broad
enough to allow for inclusion of all project costs in the revenue
requirement as well as for the inclusion of debt service
coverage, then we would suggest that serious consideration be.
given to a legislative remedy. Also, we believe that
consideration should be given to establishing rates for non-firm
energy and for capacity in addition to the present single
wholesale power rate.
With respect to power sales contracts, consideration needs
to be given to the timing of the execution of those contracts.
Contracts will have to be executed prior to the Authority's
undertaking of any revenue bond financing. However, the
Legislature may wish to establish that power sales contracts be
executed prior to major appropriations for design and
construction of projects.
STATE FUNDING
The State of Alaska's direct participation in the funding of
the costs of construction of power projects is not only unique among
other states, but has been the key to electrification of bush areas
and the construction of hydro projects that will enhance service to
the more populated areas of the State.
General Observations
Legislative ap~ropriations for power project development
have been made under several programs involving both the
Authority and other State agencies. The major programs under
which appropriations have been made include:
0 Alaska Power Authority
Power Development Fund
Power Project Loan Fund
Rural Electrification Revolving Loan Fund
Legislative Grants for Power Development Projects
0 Department of Administration
Electric Power Grants
0 Department of Community and Regional Affairs
Legislative Grants for Bush Village Electrification
After the 1982 session of the Legislature, the House Research
Agency was requested to develop an approach involving a dedicated
energy fund as an alternative to the present State funding prac-
tices. The proposal developed in response to this request was to
would provide a whole new set of jurisdictions centered on energy
management areas to assure that projects funded would have the
support of the areas that they would serve.
Alternatives for Consideration
Our consideration of alternatives to present State funding
practices focused on the proposal discussed above.
0 The State's commitment to partially fund power
projects is a basic policy decision. Likewise, a
commitment to create a dedicated fund with earmarked
revenues is also a basic policy decision.
0
0
0
The dedicated fund alternative has certain advantages in
terms of financial planning, primarily because it would
provide assurance that funds would be available for power
project financing and it would establish a formula to
determine the amount of State participation.
The proposal for the dedicated fund would involve the
formatipn of local energy management areas with their own
boards and would provide for voter approval of projects.
An alternative to this would be to provide legislative
direction to the Authority for increased consultation, and
perhaps an approval requirement, of already established
local and regional governmental agencies. Submission to
the voters for approval might be difficult because of the
complexity of the decisions.
Any alternative for State funding that would provide a
basis for the level of that funding as opposed to the
present practice of addressing the question on a project
by project basis and leaving uncertainty as to whether or
not more funds can be obtained from the State, would
enhance the Authority's ability to negotiate power
sales cont~acts prior t? c?nstructi?n ?f. the proj~cts.
Also 1 mult~year appropr1at~ons for ~nd~v~dual proJects
is another alternative for consideration.
DEBT FINANCING ALTERNATIVES
One of the more compelling reasons, if not the primary
reason, for the formation of the Authority was to provide an
entity that would have the statutory authority and the practical
capability to undertake major financings for power projects.
Although the scope of the Authority's responsibilities in this
regard has changed since its creation in 1976, power project
financing remains among the Authority's primary responsibilities.
General Observations
The Authority has successfully undertaken inteiim financing
associated with power projects under construction. It has not
yet, however, undertaken any long term revenue bond financing of
these projects. The latter is imminent, and the Authority in
consultation with its investment bankers, financial consultants,
and bond counsel has been finalizing a financing program during
the period of our work. We have had the opportunity to review
the progress of this work with the Authority and its consultants.
Our general observations with respect to the Authority's·
debt financing are as follows:
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0
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The Authority's interim financing policies and
practices are consistent with those generally utilized
by publicly owned utilities and have successfully
provided funds for construction financing.
The Authority's work with consultants and bond counsel
in developing a financing program represents a prudent
business approach.
It is important that the Legislature and other agencies
of State government involved work with the Authority to
formalize its financing program and to provide any
required statutory amendments. The timely completion
of such a cooperative effort will enhance the ability
of the Authority to successfully undertake the required
long term financing.
It is important that any required modification in the
Authority's rate directives to implement a financing
program be adopted. Particularly, if it is determined
that the existing statutes do not provide for inclusion of
debt service coverage and the operation of funds to which
those amounts would flow, legislative remedies must be
developed in a timely manner.
DISPOSITION OF POWER PROJECTS
The questions addressed under this subject pertain both to
ownership and operation of the Authority's projects upon completion.
Our discussions with the Authority's bond counsel and invest-
ment bankers indicate that there is very little flexibility with
regard to the question of ownershipo If the Authority undertakes
debt financing for a particular project, title to that project will
have to be·vested in the Authority. It is suggested that any
further questions on this subject should be directed to the
Authority's bond counsel or the Attorney General.
With respect to the operation of completed projects, there is
considerably more flexibility. Financing considerations dictate
that assurance be provided that the projects will be operated and
maintained by an agency that is competent to do this work. There-
fore, any arrangement for operation and maintenance may have to be
disclosed at the time of financing. Again, this question needs to
be addresssed by the Authority's financial advisors and bond
counsel.
Alternatives that should be considered with respect to
operation and maintenance of completed projects include the
following:
0
0
The Authority could operate and maintain all projects
that they finance •.
Projects could be operated by the local utility serving
the area where the ·project is located under a contrac-
tual arrangement. (This has been done with the Solomon
Gulch Project.)
0 Even as the Authority contracts for the operation and
maintenance of one or more of its projects, certain
economies of scale can be achieved if the Authority would
maintain responsibility for, for example, training of
plant operators, major overhauls, maintenance of spare
parts and other activities of this nature.
A number of power generation facilities have been constructed
throughout the State with funds appropriated by the Legislature or~
obtained from State agencies other than the Authority. An alter-
native for operation of these projects that we believe should be
considered would be a requirement, as a condition of providing
funds, that arrangements be made for operation and maintenance of
the generation facility. For example, the Alaska Village Elec-
tric Cooperative might be able to efficiently fulfill this
function within their service area.
'
SECTION 2
ALASKA POWER SUPPLY
INTRODUCTION
A number of organizations are involved in energy research,
development, and management activities directly and indirectly
related to power supply in Alaska. Nearly every agency or depart-
ment of State, local, and the federal government is involved to
some degree in energy related pursuits. This section of the report
will provide an overview of the institutions and legislative direc-
tion relating to Alaska power supply.
There are several Federal Agencies operating in Alaska whose
energy activities influence the lives and livelihoods of Alaskans.
The most active of these is the Alaska Power Administration of the
u.s. Department of Energy.
The agen~ies, activities, and programs within the Alaska State
government are also analyzed and discussed in some detail in this
section. The agencies which will receive the most in-depth discus~
sion are the Division of Budget and Management and the Division of
Policy Development and Planning in the Office of the Governor; and
the Alaska Public Utilities Commission, the Alaska Power Authority,
and the Division of Energy and Power Development of the Department
of Commerce and Economic Development. These are the key State
organizations involved in energy activities in Alaska.
Power supply planning in Alaska differs from the lower 48
states in that a State agency under the control of the Legislature
and Governor (the Authority) serves as the wholesale power mar-
keting agent for power from State owned facilities. Alaska has
invested substantial sums in the development of power projects.
Therefore, the State has a vested interest in all phases of power
supply by reason of both its overall energy policy concerns and its
participation in power project financing.
Finally, one further point warrants mention; public agencies,
utilities, private enterprise, and special interest groups are all
2-1
involved in Alaska Power Supply. As a result, no entity has a mono-
poly on power and energy within Alaska. In fact, energy activities
within Alaska are incredibly diversified, ranging from economic
assistance for high cost power or fuel to research, development and
demonstration programs for power supplies.
As a result, there is considerable duplication of effort in
Alaska. The State organizational structure in particular is
characterized by overlapping responsibilities and confusing lines
of authority. State energy policy has not always been consistent
either, and this has hindered the development of a coordinated
energy plan. This problem has grown with the size and wealth of
the State. The majority of Alaska energy programs did not exist
five years ago, therefore, the transition has not been smooth and
coordinated in all cases. In the interest of charting this
evolution, the following presents a discussion of several of the
key agencies charged with developing Alaska's energy future. A
list of Alaska utilities is also provided in Appendix 2-A.
Federal Agencies
There are several Federal Agencies operating in Alaska whose
activities are of direct concern to Alaskans. A summary outline of
these agencies is provided below, and a complete list of these
agencies and their specific programs is provided in Appendix 2-B.
Federal Agencies
Department of Energy
Alaska Power Administration
Alaska District Corps Qf Engineers
Internal Revenue Service
Farmers Home Administration
u.s. Forest Service
u.s. Department of Agriculture
u.s. Department of Housing and Urban Development
2-2
State Agencies
As can be seen from the figure below, nearly every office
and department within the Alaska State organization is involved
in energy related activities. Some are more active than others,
and these will receive more attention in our report as warranted.
A comprehensive list of all energy related agencies and their
respective programs is provided in Appendix 2-B.
Alaska Organization and Administration of Departments
Conducts Specific Office or Department
Energy Related
Activities
X Office of the Governor
X Department of Administration
X
X
X
X
X
X
X
X
X
Department of Law
Department of Revenue
Department of Education
Department of Health and
Social Servi~es
Department of Natural Resources
Department of Commerce and
Economic Development
Department of Transportation and
Public Facilities
Department of Community and
Regional Affairs
Department of Public Safety
Department of Military Affairs
Department of Fish and Game
Department of Labor
Department of Environmental
Conservation
2-3
Important Energy
Activity Detailed
in Report
X
X
X
X
This section of the report contains a brief description of
several of the key federal and State organizations involved in
evergy planning, development, and management activities in Alaska.
Those chosen were selected on the basis of compatibility and rele-
vance to report goals. Their responsibilities, programs, and
organization are chronicled. T~is is al~o accompanied by a brief
survey of their status in the recent past. The order of presenta-
tion is as follows: a federal agency is discussed first, followed
by the Office of the Governor, and concludes with an account of
relevant State agencies within the Department of Commerce and Eco-
nomic Development.
ALASKA POWER ADMINISTRATION
The Alaska Power Administration (APA), a federal power agency,
was established in 1967 as a unit of the Department of the Interior
and became a branch under the Department of Energy on October 1,
1977. The APA headquarters are in Juneau, Alaska, and they report
to the Assistant Secretary of Energy for Resource Applications.
The APA operates, maintains, and markets power for Alaska's
two Federal hydroelectric projects-the 47,160 kw Snettisham
Project near Juneau, and the 30,000 kw Eklutna Project near
Anchorage. The agency is also involved in transmission studies and
studies of future water and power potential. Through cooperation
with the Corps of Engineers, the State of Alaska and other
entities, the agency's activities encompass economic and financial
analysis, environmental evaluations, estimates of future energy
demand, and engineering and cost studies.
The APA is divided into three major divisions that report to
an administrator who, ih turn, reports to the Assi~tant Secretary
of Conservation and Rene~able Energy. These three divisions are:
the Planning Division, the Power Division, and the Administrative
Division.
In recent years, the APA has placed high priority on
implementing President Carter's Solar Pricing Program, which
instructed Federal Power Marketing Administrations to increase
their conservation efforts and renewable resources development.
They responded by increasing the rate of utilization of Snettisham
2-4
power, expanding the peaking capability of the Eklutna Project, and
by committing funds to exercise renewable resource options and
implement conservation programs.
OFFICE OF THE GOVERNOR
'
Two divisions in the Office of the Governor have been involved
in Power Project Development. This is in addition to the continuing
involvement of the Governor and members of his staff in all aspects
of the program.
Division of Budget and Management
The primary function of the Dtvision of Budget and Management
(DBM) is the review of budget and program activities of all Alaska
State agencies. DBM has had significant involvement in Alaska's
Power Project Development Program through its review of the Author-
ity's budget and of their reconnaissance and feasibility studies.
Not only does DBM review these studies for the Legislature and
Governor, but DBM staff has worked closely with Authority staff in
developing methodology and improving the general quality of the
work.
Although there has been controversy at t~mes between DBM and
the Authority, it is our observation that DBM's involvement has been
positive and that the Authority's management and staff have care-
fully considered suggestions offerred by DBM's staff.
Division of Policy Development and Planning
The Division of Policy Development and Planning (DPDP) is the
primary policy analysis org~nization of the State. Their primary
involvement in the Power Project Development Program relates to the
Railbelt area. To assure objectivity in the analysis of
alternatives to the Susitna Project, DPDP undertook these studies.
The work was actually done by consultants, but supervised by DPDP.
2-5
THE DEPARTMENT OF COMMERCE AND ECONOMIC DEVELOPMENT
The Department of Commerce was established as a State agency
in 1959 (Ch 64 SLA 1959). It was renamed the Department of
Commerce and Economic Development (DCED) in 1976 to more accurately
reflect its activities. The DCED's principal energy related respon-
sibilities and duties include:
0
0
0
0
0
0
0
0
Administering State programs which relate to commerce,
enforcing the laws relevant to those programs, and
adopting regulations consistent with those laws
Registering corporations and collecting their franchise
taxes
Enforcing the State laws which regulate public utilities
and other public service enterprises
Conducting studies, entering into contracts, and making
surveys which relate to the economic development of the
State and, when appropriate, analysing, assembling, and
dispersing the findings obtained
Collecting raw data from businesses, individuals, and
other organizations which will aid the Department in
formulating economic impact information
Formulating a continuous program for basic economic
development, and establishing and activating programs
which will achieve balanced economic development
Advising the Governor on economic development policy
matters and administering the economic development
programs of the State
Reviewing annual reports and programs of State agencies,
and preparing an annual report on the economic status of
the State
The DCED's power development role is complimented by several
divisions, offices, commissions, and public corporations over which
it has varying degrees of administrative control. This account-
ability ranges from subordinate organizations within the DCED, to
public corporations of the State within the DCED but which have a
legal existence independent of and separate from the State.
2-6
In the latter case, the exercise by the corporation of the powers
granted to it is considered an essential function of the State, and
the role of the DCED is limited to that of a supervisory body.
An overview of the organization of the DCED is furnished
below. A more detailed summary of the divisions ~ithin the DCED
and their respective energy related programs and activities is
provided in Exhibit 2-1 on the following page.
Department of Commerce and Economic Development
Division of Energy and Power Development
Division of Business Loans
Office of Mineral Development
Office of Special Industrial Development
Alaska.Royalty Oil and Gas Development Board
Quasi-Independent Entities
Alaska Public Utilities Commission
Alaska Power Authority
Alaska Renewable Resources Corporation
2-7
Summary of
Department of Commerce and Economic Development Divisions
and their Energy~Related Programs and Actiyities
Division of Energy and Power Development
0
0
0
0
0
0
0
0
0
Residential Energy Conservation Program
Low-Income Weatherization
Energy Planning (Long-Term Energy Plan)
Energy Field Offices and Education Program
Energy Research, Development and Demon~tration
Projects
Appropriate Technology Small Grants Program
REAA Grants Program
Institutional Buildings Grants Program
Residential Building Lighting and Termal Standards
Division of Business Loans
0
0
0
Alternative Technology Revolving Loan Fund
Bulk Fuel Revolving Loan Fund
Residential Energy Conservation Loan Fund
Office of Mineral Development
Office of Special Industrial Development
Alaska Royalty Oil and Gas Development Board
Quasi-Independent Entities
Alaska Public Utilities Commission
Alaska Power Authority
0 Reconnaissance, Feasibility Studies
0 Power Project Loan Fund
0 Power Cost Assistance Fund
0 Rural Electrification Revolving Loan Fund
0 Power Development Fund
0 Legislative Grants for Power Development
Alaska Renewable Resources Corporation
0
0
Alaska Renewable Resources Development Fund
Alaska Renewable Resources Investment Fund
Alaska Renewable Resources Permanent Fund
2-8
EXHIBIT 2-1
Division of Energy and Power Development
The Division of Energy and Power Development's (DEPD) goal
is to assure that Alaska's energy needs are met as efficiently as
possible. Its prime concern is in the development, management, and
efficient use of the State's energy resources. Conservation and a
commitment to reducing the State's dependence on fossil fuel
generation are two additional concerns of the DEPD.
The DEPD was created in 1960 (Ch 135 SLA 1960) as part of
the Department of Commerce. It was not funded until 1974 and has
been amended twice--in 1976 to reflect the changes made in the
Department of Commerce's name, and in 1980 to require certain energy
conservation functions.
Its specific duties as required by statute are:
0
0
0
0
0
0
0
0
Study the State's water, fossil fuel, and other power
resources and collect and disseminate information
relating to them
Study existing and potential uses and markets for
electric power and energy1 promote and encourage the
development of major markets
Encourage .and assist rural electrification, energy
efficiency programs, and the development of power grids,
power pools, and solar energy
Prepare a State Long Term Energy Plan; adopt thermal and
lighting energy standards for non-public buildings; and
establish a training and certification program for energy
auditors
Cooperate with federal, state, and local agencies as well
as private companies interested in the development and
use of Alaska's energy and other natural resources
Coordinate and represent the State's interest in securing
f~deral participation in the development and financing of
large-scale, low-cost power projects
Make grants to school districts and regional educational
areas for planning, developing, and implementing energy
efficient standards for rural educational facilities
Supply State grants to match any grants made by the
Department of Energy under the Appropriate Technology
Small Grants Program
2-9
The DEPD carries out its activities through six programs:
Energy Administration, Energy Assessment and Programs, Energy Engi-
neering, Conservation, Information Services, and Education and Field
Offices.
Energy Administration
This section assimilates energy policy decisions and provides
the DEPD with planning and management directives as well as support
facilities. The Energy Administration Section is supported by three
groups: accounting, grants administration, and clerical.
Energy Assessment and Programs
This section's functions include: long term energy planning,
resource development planning, in-state energy supply and demand
. forecasting, and energy policy and planning activities. Some speci-
fic planning activities which this section undertakes are:
0
0
0
0
0
Alaska Long Term Energy Plan
Assessment of Energy Technologies
Energy Emergency Contingency Plan
Energy Conservation Evaluation
Alaska Energy, Resource Development, and Economic Future
Study
Energy Engineering
A technical appraisal of energy issues is the major assignment
for employees within this section. They are responsible for the
operation of the DEPD's research development and demonstration pro-
jects. The projects themselves.are concentrated in the following
areas:
0 Wind
0 Peat
0 Geothermal
2-10
0
0
0
0
Biomass/Wood
.Energy Use and Transformation
Miscellaneous Technologies
Alaska Energy Center Projects
(transferred to the DEPD from the Alaska Energy)
Energy Conservation
Alaska's residential energy conservation programs are the
primary responsibility of this section. Three of its activities
include:
0 Residential Energy Audits
0 Low-Income Weatherization Program
0 Energy Conservation Grants and Refunds
Information Services
The Public Information Sector collects, prepares, and dissemi-
nates timely energy information to the public. It publishes a
quarterly newsletter and an Energy Resource Handbook.· It also
produces radio and television programs and serves as the public
relations arm. The section also provides a liason with the Legis-
lature and analyzes energy ~elated legislative developments.
Field Offices and Education
Through its field offices the DEPD establishes contact with
most areas of Alaska. It accomplishes this goal through five
vehicles:
0
0
0
0
0
Anchorage-Southcentral Field Office/Energy Information
Clearinghouse
Juneau-Southeast Field Office
Fairbanks-Interior Field Office
Education Programs
Technical Reference Library
2-11
ALASKA PUBLIC UTILITIES COMMISSION
The Alaska Public Utilities Commissionn (APUC} was created in
1959 (Ch 199 SLA 159) within the Department ,of Commerce_ (renamed
the Department of Commerce and Economic Development in 1976}. It
consists of five members who are appointed by the Governor and
confirmed by the Legislature, and whose terms of office are six
years.
Among the general powers and duties of the APUC are:
0
0
0
0
0
0
0
0
0
Regulation of every public utility engaged or proposing
to engage in the utility~business insidp the State except
for municipal utilities
Jurisdiction includes the following types of utility
services: electric, gas, steam, water
Investigations of the rules, regulations, rates,
classifications, services, and facilities of public
utilities
Shall hold rate hearings and approve rates
Shall ensure that public utilities charge rates that are
just, fair, and reasonable
Shall prescribe the system of accounts and require public
utilities to file reports and other information and data
Shall regulate the service and monitor the safety of
operations of public utilities
Shall develop PURPA Regulations
Appear personally or by counsel and represent the
interests and welfare of the State
The APUC also is r-equired to publish and submit to the
Legislature an annual report reviewing its work in the previous
year, plus an outline of the Commission's program for the develop-
ment and regulation of public utility services in the forthcoming
year.
In addition, the APUC requires each public utility to provide
it with a a complete tariff showing the rates charged to all
classes of customers. It further stipulates that rates shall be
2-12
just and reasonable, and non-discriminatory or preferential. If
the APUC determines that a utility's rates do not conform to these
criteria, it is empowered to determine its own estimate of a just
and reasonable rate and can establish it by order.
No public utility may operate within Alaska without first
having obtained from the APUC a certificate declaring that public
convenience and necessity require or will require the service. If
two or more public utilities are competing to provide identical
service to the same area and this competition is not in the public
interest, the APUC is authorized to take appropriate action to
eliminate the competition or any undesirable duplication of faci-
lities. Furthermore, those utilities receiving certificates must
furnish and maintain adequate, efficient, and safe service and
facilities. The service provided also must be reasonably continu-
ous and without unreasonable interruption or delay. In the event
a utility fails to conform to any of these provisions, the APUC
may order an investigation, formal hearing, or a review of the
utility's license privilege.
ALASKA PQWER AQTHORITY
The Alaska Power Authority (Authority) is a public
corporation made up of a seven member Board of Directors who are
appointed by the Governor and confirmed by the Legislature. It
was created in 1976 (Ch 278 SLA 1976), but it was not actually
funded and staffed until 1978. A staff of 32 conducts the day-
to-day business of the Authority from offices in Anchorage.
"The role of the Authority is to identify, evaluate, and
develop electrical power production facilities utilizing the most
appropriate technology from among those that are commercially
available (except . nuclear .generation). ".l/ . The Au-t;hori ty is
authorized to conduct reconnaissance and feasibility studies;
issue bonds; design, construct and operate projects; and enter
into contracts for power sales. The extent of their involvement
in any power project depends on local needs and preferences,
project specifics, and State budget priorities. Power project
facilities can be studied, financed, constructed and owned by the
Authority, but in some cases their involvement is confined to
2-13
'
financing alone, or just to the early phases of project investiga-
tion, evaluation, and/or development.
The creation of the Authority was necessary due to the pecu-
liarities of long term energy planning in general, and the geogra-
phy and energy needs of the State of Alaska specifically.
The Legislature recognized this situation as early as 1960 when
they laid the groundwork for an agency whose primary responsi-
bility would be electrical power development~-the DEPD in the
Department of Commerce. A State power development plan was
required by the original 1960 legislation, but the first pl~n was
not produced until 1980.
In 1976 the Legislature reached a concensus on Alaska's
energy development and long term economic growth policies. The
1976 Legislature passed a Legislative Finding and Policy section
in Article 1 of the Alaska Power Authority Bill (Ch 278 SLA 1976)
which stated:
(a) The Legislature finds, determines and
declares that
(1) there exist numerous potential
hydroelectric and fossil fuel generating sites in
the State;
(2) the establishment of power projects at
_these sites is necessary to supply power at the
lowest reasonable cost to the State's municipal
electric, rural electric, cooperative electric,
and private electric utilities, and regional
electric authorities, and thereby to the consumer
of the State, as well as to supply existing or
future industrial needs; (HB 442 1978)
(3) the achievement of the goals of lowest
reasonable consumer power costs and beneficial
long-term economic growth and of establishing,
operating and developing power projects in the
State will be accelerated and facilitated by the
creation of an instrumentality of the State with
powers to construct, acquire, finance, and
operate power projects (HB 442 1978)
(b) It is declared to be the policy of the State,
in the interests of promoting the general welfare of
all the people of the State, and public purposes, to
reduce consumer power costs and otherwise to encourage
the long-term economic growth of the State, including
the development of its natural resources, through the
establishment of power projects by cr~ating the public
2-14
corporation with powers, duties, and functions as
provided in this chapter. 2/
In order to achieve the goals of its policy, the State found
that hydroelectric projects should be considered the most desir-
able new resource option. Hydroelectric projects appeared to
ensure the State of a supply of long term, stable priced and
secure electrical power.l/
However, it was discovered that financing constraints often
argue against the construction of the most cost effective project.
The problem arises because high, front-end construction costs
(which are sensitive to inflation) cause wholesale power rates to
be much higher than other alternatives in the early years of
project life. The problem is also compounded by the sheer magni-
tude of the financing which must be secured to even conduct the
preliminary investigations, let alone the actual construction.
This set of circumstances makes it very difficult for a single
utility or an association of utilities to embark on such a project
even if it were proven feasible.
Hence, it was decided that the situation required State
intervention. Other agencies could carry out reconnaissance,
feasibility, design and construction activities, but a public
corporation would be the perfect vehicle for achieving the State's
purposes in this instance. By its status as a public corporation
the Authority could sell bonds, subject to IRS regulations, whose
interest to bondholders would be tax free. This feature would
lower the cost of debt capital. When combined with existing State
financing instruments, Alaska would have a more diversified pool
of financing alternatives whose combined cost of borrowed capital
was much lower and whose investor attraction was much greater.
With this in mind, the electric power development function
was transferred from the DEPD and became the primary responsi-
bility of the Authority in 1976. It was set up as a public
corporation of the State in the DCED, but with separate and inde-
pendent legal existence. The Authority and the DEPD do collabo-
rate, however. For example, they both work together in formu-
lating the State of Alaska Long Term Energy Plan and its annual
revision.
2-15
Among the specific powers the Authority was granted by Chapter
83, "The Omnibus Energy Bill," are:
0
0
0
0
0
To acquire, whether by construction, purchase, gift or
leas.e, and to improve, equip, operate, and maintain
power projects
To issue bonds to carry out any of its corporate
purposes and powers ••• and to deposit and invest its
funds subject to agreements with bondholders
To sell, lease as lessor or lessee, exchange, donate,
convey or encumber in any manner ••• real or personal·
property owned by it, or in which it has an interest •••
To perform reconaissance studies, feasibility studies,
and engineering and design with respect to power
projects
To enter into contracts or agreements with respect to
the exercise of any of its powers (with the United
States or any person), and do all things necessary and
convenient to carry out its corporate purpose and
exercise the powers granted in AS 44.83.010-44.83.510 AI
In addition to those mentioned above, the Authority has
specific powers which relate to the financing methods that it can
·recommend to the Legislature. To ~ccomplish its mission of
assisting utilities and others with the development and operation
of power projects by providing loans and grants; issuing bonds;
and preparing feasibility, reconnaissance, plans of finance, and
engineering and design studies, the Authority can recomend to the
Legislature:
0
0
0
The issuance of general obligation bonds of the State
to finance the construction of a power project if the
Authority first determines that the project cannot be
financed by revenue bonds of the Authority at
reasonable rates of interest;
The pledge of the credit of the State to guarantee
repayment of all or any portion of revenue bonds issued
to assist in construction of power projects;
An appropriation from the General Fund
For debt service on bonds or other project
purposes; or
To reduce the amount of debt financing for the
project;
2-16
0
0
0
0
An appropriation to the Power Project Fund for a power
project1
An appropriation of a part of the income of the
Renewable Resources Investment Fund for a power
project1
Development of a project under flnancing arrangements
with other entities using leveraged leases or other
financing methods.
An appropriation for a power project acquired or
constructed under the Energy Program for Alaska.5/
The existence of two potential sources of funds for
development of renewable energy projects--the Authority and the
State of Alaska--expands the range of financing alternatives. The
financing arrangements available to parties within Alaska are:
0 Alaska Power Authority Revenue Bonds
0 State General Obligation Bonds
0 Revenue Bonds with State Guarantee
0 State General Fund Appropriation
Debt Service Payment
Reduction of Bondable Costs
0 State General Fund (Equity Investment)
0 Non-State Assistance
Federal (REA & FFB)
CFC
0 Leveraged Leases
Other Third Party Financing Methods
The purpose of the State assistance in whatever form is to
lower the cost of borrowed capital for the development of projects
and the cost of energy to consumers. The latter factor is espe-
cially critical when the project is a capital intensive project,
and the greatest benefits to the consumer are realized in the
2-17
early years of project operation.i/ However, under current
legislation where debt service costs must be incorporated into
wholesale power rates, the objective of reducing initial consumer
power costs for hydro projects is not always fulfilled to the
maximum extent possible due to the considerable markup in rates
which these financing costs impose. Debt financing (under current
legislation) will not necessarily provide the consumer with inex-
pensive power or "an early break" when a substantial amount of the
project cost is financed through debt and an equally substantial
amount of debt service costs are incurred early in the project's
life.
Specific Programs
To carry out its power development role the Authority admini-
sters four specific programs: the Power Project Loan Fund, the
Power Cost Assistance Program, the Rural Electrification Revolving
Loan Fund, and the Energy Program for Alaska (which has a Power
Development Fund). These programs were established at different
times and amended, renamed, and their functions revised as the
Legislature built a comprehensive energy plan. When the Authority
was first created it only administered one program. Today there
are four specific programs which compliment its power development
role. A chronological history of the Authority and the DCED,
showing the changes in their structure and programs, is presented
in Exhibit 2-2. From this chart it is apparent how much these
agencies have grown and changed over time.
In addition to its specific programs, the Authority also has
general authority to promote power development. For example, the
Authority can issue bonds outside of the Energy Program for Alaska.
It can also provide loans to individual utilities from funds which
are appropriated to the Authority generally, as opposed to those
which are conditionally dedicated by the Legislature to specific
programs. These options, combined with the other four programs,
give the Authority considerable flexibility in power development.
2-18
Power Project Loan Fund
The Power Project Loan Fund was formerly known as the
Power Project Revolving Fund. It was established in the original
legislation (Ch 278 SLA 1976) that created the Authority. Its
purpose was to loan funds to cities, boroughs, and others1 to
conduct necessary studies1 and construct power projects. The
statutes governing this program were amended in 1978 and in 1980.
The most significant changes made concerned the source of funds
for the program (Ch 83 SLA 1980 provided that the fund include
only money apopropriated by the Legislature and would not include
interest earned on the loans as it had previously), and the
authorized uses for loans from the fund (Ch 156 SLA 1978 expanded
and explained these in greater detail).
The present statute declares that the Power Project Loan Fund
is established to provide loans to electric utilities, regional
electric authorities, municipalities, cities, boroughs, regional
and village corporations, village councils, and non-profit
marketing cooperatives; or borrowers who allow the above entities
to operate a project under third party or leveraged lease
financing arrangements.
To be eligible for assistance, potential recipients must meet
and follow certain standards, procedures, and criteria as deter-
mined by the Authority, and they must prove that they need the
loan to cover the costs of various non-nuclear expenses. Valid
expenses include: reconnaissance studies, feasibility studies,
license and permit applications, preconstruction engineering,
design of power projects, construction·, equipping, modifying,
improving, and expanding power production facilities and trans-
mission and distribution facilities. In fact, loans can be used
to pay most costs except those of debt service, bond defeasance
costs, or operation and maintenance costs. In addition, to
receive a loan, the applicant must "demonstrate to the Authority
that the financing arrangement for the power project will reduce
project financing costs below costs of comparable public power
projects."l/
Loans for power projects from the fund carry an interest rate
which is not less than five percent, nor greater than the average
2-20
weekly yield of municipal bonds for the 12 months preceding the
date of the loan. The term of the loan may not exceed 50 years.
Loans of 25 years or less for diesel generation, and 35 years or
less for hydroelectric projects are common.
Power Project Loan funds are distinct from any other money
or funds of the Authority and include only money appropriated by.
the Legislature. Loan repayments and interest earned on the
loans outstanding from the fund are deposited in the State
General Fund.~ As of August 4, 1981, the Legislature had
appropriated a total principal amount of $25,070,000 plus
interest.
Power Cost Assistance Program
In 1980, the Power Production Cost Assistance Program was
established to provide a State subsidy to high-cost residential
power. Thereafter, the 1981 Legislature retitled it the Power"cost
Assistance Program and the qualifications and level of assistance
were changed.
The program has a fund which is administered by the
Authority as a fund distinct from other funds, and it is composed
of money appropriated for the purpose of providing power cost
assistance to eligible electric utilities. The 1980 Legislature
established the program with a total funding of $2,621,000 • For
the fiscal year ending June 30, 1981, program expenses were
$2,287,735. Fifteen utilities received Power Production Cost
Assistance during 1981. The program is funded through FY 1982.
The APUC determines utility power costs and eligibility, and
it determines the amount of State assistance per kilowatt-hour
sales for individual utili ties~· ·The Authority disburses the· funds
to eligible utilities based on the iecommendations of the Commis-
sion and statements of sales to eligible customers submitted by
eligible utili ties.
An electric utility can receive power cost assistance for
sales of power to local community facilities. The subsidy is
calculated in the aggregate for each community served by the
qualified utility. It is based on actual consumption of not more
than 55 kilowatt-hours per month for each resident and not more
2-21
than 600 kilowatt-hours per month sold to each customer other
than local community facilities. Power cost assistance payments
are used to reduce the cost of all power sold to local community
facilities, in the aggregate, to the extent of 55 kilowatt-hours
per month per resident of the community, and to reduce the cost
of the first 600 kilowatt-hours per customer per month for all
other classes served by the utility. The amount of relief per
kilowatt-hour provided to the utility as determined by the
Commission may not exceed the average rate per eligible kilowatt-
hour sold, or 95 percent of the power cost, which~ver is less.
In addition, to receive assistance, a utility's power costs must
be greater than 12 cents per kilowatt-hour and less than 45 cents
per kilowatt-hour (the base level of support for FY 1983 will
increase one cent per kilowatt-hour from 12 cents to 13 cents,
plus one cent per kilowatt-hour for each fiscal year thereafter).
An eligible utility may not be denied the benefits of this pro-
gram because complete cost information is not available. Needy
utilities are assisted by the Commission so that they may supply
the information the APUC considers pecessary to comply with the
program requirements. Therefore, power cost assistance can be
determined even for utilities with no historical kilowatt-hour
sales data.
A utility whose customers receive benefits from this program
must specify in each billing period for which a State subsidy is
received: the rate without power cost assistance, the amount of
power cost assistance per kilowatt-hour sold, and the rate
charged to the customer (which is the difference between the two
amounts).
To be entitled to receive power cost assistance, each
electric utility must:
0
0
Maintain accurate records that contain the information
necessary to comply with program requirements.
Report monthly to the Authority in the time and form
which the Authority requests.
2-22
0
0
0
0
0
Use metering equipment which measures individual
customer power consumption and the utility's overall
fuel consumption.
Meet customer consumption restrictions discussed
previously.
Provide its customers with a notice, continuing
information stipulated by the Authority, which
describes the power costs with and without the
program and the amount of State aid.
Cooperate with the appropriate State agencies.
Be willing to eliminate unnecessary or duplicative
operating expenses as requested by the APUC.
The legislation, in a separate section, included specific
provisions and conditions under which the amount of power cost
assistance could be adjusted by the APUC. A section was
also included so that utilities who are not regulated by the APUC
could receive power cost assistance. Their requirements are
almost identical to those of utilities which are regulated by the
APUC.
Rural Electrification Revolving Loan Fund
The Rural Electrification Revolving Loan Fund was estab-
lished in the Authority by SB 25 (Ch 118 SLA 1981) for the purpose
of assisting electric utilities in extending new electric service
into unserved areas of the State. The fund consists of appropria-
tions made to the fund, and interest and principal payments on
loans made from the fund.
Loans from the fund are made only to electric utilities
certified by the APUC and must be approved by the Authority and
recommended by a loan advisory committee made up of local
residents of the area to be served by the applicant.
Loans are made at two percent interest with interest charges
recovered through appropriate retail rate increases. Principal is
repaid as future service connections are added to the extension.
When the Authority receives an application for a loan, it
appoints a local advisory committee to consider the request. To
2-23
receive a favorable recommendation from the group, the applicant
must show that the proposed extension will provide immediate
service for at least three customers and that its installation
will generate sufficient revenues to repay the loan within 10
years.
Energy Program for Alaska
SB 25 (Ch 118 SLA 1981) established the Energy Program for
Alaska (Energy Program) in the Authority. The Energy Program was
created to facilitate the financing and construction of non-
nuclear power projects through direct State appropriations. It
was also intended to provide a mechanism for pooling the costs of
debt financed projects. Funds for the Energy Program were pro-
vided by a newly created Power Development Fund that was supplied
with State appropriations, plus any revenues collected from power
sales which were not required by law to be deposited in the
General Fund.~ The Authority is authorized to acquire or con-
struct power projects with money from the Power Development Fund.
Resources expended from the Power Development Fund are consi-
dered as State investments or grants. This contrasts with the
status of the monies allocated from the Power Project Loan Fund
because they are classified as loans which must be repaid.
Monies from the fund can be used for reconnaissance and
feasibility studies and project finance plans; project design,
licensing and construction costs; the defeasance of bonds or the
payment of debt service on loans or bonds issued for power
projects; and the costs of operating and maintaining power
projects. However, "money in the fund can be used only for a
power project that provides the lowest reasonable power cost to
utility customers in the market area for the estimated life of
the power project."lQ/
A power project can be acquired or constructed as a part of
the Energy Program only if the project is submitted to, arrl
approved by, the Legislature.ll/ To be approved, a proposed
project must complete and pass the following steps:
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Reconnaissance study
Review of the reconnaissance study by the Division of
Budget and Management
Feasibility Study and Finance Plan
Review of feasibility studies and plans of finance by
the Division of Budget and Management
Submission to th& Legislature (by the Authority)
If the project is approved, the Legislature passes a new law
authorizing the expense of funds. The proceeds from the
appropriation are invested by the Department of Revenue, and
money from the fund is provided to the Authority only after a
project cost is incurred.
Power projects that are acquired or constructed as part of
the Energy Program may be:
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Owned by the State and administered by the Authority.
Owned by the State, but operated by a qualified utility
through a contract or lease entered into by the
Authority and the qualified utility (the Authority is
guided by specific regulations which detail the
procedure for selecting the "qualified utility" when
there is more than one wholesale power customer to be
served directly by the power project).
Leased under reasonable terms and conditions to an
applicant utility when that party is the only wholesale
power customer to be served directly by the project
(the Authority must enter into a contract or lease with
the applicant unless they are determined to be
incapable of operating the power project).
When the Authority allows a project to be operated by
another party, it must review and approve the annual budget for
the operation and maintenance of the power project.. It must also
assure that the facility is being operated efficiently and in a
manner that is consistent with national standards for the power
production industry.
As a wholesale power marketing agency, the Authority sells
energy from its projects. A utility that desires to purchase
2-25
energy produced from Authority projects must agree with the
Authority to:
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Give preference in the retail sale of power to all
classes of consumers except industrial consumers.
Charge industrial consumers a rate that is greater than
the wholesale power rate, but that is less than the
rate charged residential consumers.
The Authority establishes a wholesale power rate structure
for sales of power to its customers at the bus bar of the power
project. Under current State law (HB 9), each power project
acquired or constructed under the Energy Program has its own
wholesale power rate. The costs which the Authority uses to
determine the revenue requirements which the operation of the
project must produce are:
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Operation, maintenance, and equipment replacement costs
of the power project
The power project's proportionate share of debt service
on State loans and bonds for all power projects in the
Energy Program for Alaska (with a share limit or "cap")
Safety inspections and investigations of the power
project by the Authority
The Authority transmits all the money it receives to the
Commissioner of Revenue for deposit in the State General Fund
except money it has pledged to secure bonds in accordance with
contracts with bondholders.
Lastly, the Energy Program legislation included provisions
concerning energy conservation. The Authority is directed to
ensure that cost-effective energy conservation measures are
implemented by the communities which receive benefits from the
Energy Program.
2-26
APPENDIX 2-A
ALASKA UTILITIES
Alaska Electric Light and Power Company (Juneau)
MlFAC Foods, Inc. (Sand Point on Popov Island)
Anchorage 11unicipal Light and Power
Alaska Power Administration-Eklutna (Anchorage)
Alaska Power Administration-snettisham (Juneau)
Aniak Power Company
Alaska Power & Telephone Company (Craig, Hydaburg, Skagway, Tok,
Dot Lake)
Alaska Village Electric Cooperative, Inc. (48 villages)
Arctic Utilities, Inc. (Deadhorse)
Barrow Utilities & Electric Cooperative, Inc.
Bethel Utilities Corporation, Inc.
Bettles Light & Power, Inc.
Circle Electric
Chugach Electric Association Inc. (Anchorage Area)
Cordova Electric Cooperative, Inc.
City of Manokotak
City of Unalaska
Chistochina Trading Post
Copper valley Electric Association, Inc. (Glennallen, Valdez)
Dot Lake Electric, Inc.
Fairbanks Municipal Utilities System
Fort Yukon Utilities
Glacier Highway Electric Association, Inc. (Juneau Area)
Golden Valley Electric Association, Inc. (Fairbanks Area)
Homer Electric Association, Inc, (Kenai Peninsula)
Haines Light and Power co., Inc,
Hughes (Esther J. James)
Iliamna-Newhalen Electric Cooperative, Inc. (I-N, Nondalton)
Kodiak Electric Association Inc.
Klukwan Electric Utility
Kotzebue Electric Association, Inc.
Ketchikan Public Utilities
M&D Enterprises (Galena)
Matanuska Electric Association, Inc. (Eagle River, Palmer-
Talkeetna Area)
Manley Utility Co., Inc, (Manley Hot Springs)
Metlakatla Power and Light
McGrath Light & Power
Napakiak Corporation
Naknek Electric Association, Inc.
Nushagak Electric Cooperative, Inc. (Dillingham)
~likolski Power & Light Co.
Nome Light and Power Utilities
Northern Power & Engineering Corporation, Inc. (Cold Bay)
Northway Power & Light, Inc.
No. Slope Borough Power & Light System (Atkasook, Kaktovik,
Wainwright, Point Hope, Point Lay, Nuiqsut, Anaktuvuk Pass)
Paxson Lodge, Inc.
Petersburg Municipal Power and Light
Pelican Utility Company
Sitka Electric Department
Seward Electric System
Semloh Supply (Lake 11inchumina)
Teller Power Company
Tlingit-Haida Regional Electrical Authority (Angoon, Hoonah, Kake,
Kasaan, Klawock)
Tanana Power Company
unalakleet Valley Electric Cooperative
Wrangell Municipal Light and Power
Weisner Trading Co.
Yakutat Power, Inc. 2-27
APPENDIX 2-B
SUMMARY OF ENERGY OROGBAMS WITHIN ALASKA
Federal Agencies
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Department of Energy
Activities:
State energy production and use data
Federal/State energy programs
Energy Extension Service Program
Low Income Weatherization Program
Institutional Buildings Program
Alaska Power Administration
Activities:
Power Supply Studies & Project Operation
Alaska District Corps of Engineers
Activities:
Inventories
Reconnaissance Studies
Feasibility Studies
Internal Revenue Service
Residential Energy Tax Credit
Business Energy Tax Credit
u.s. Department of Agriculture
Solar Grain Drying Loans
Farmers' Home Administration
Home Improvement Repair Loans and Grants
u.s. Forest Service
Wood Energy Program
State of Alaska
Legislature
Division of Legislative Finance
Division of Legislative Audit
Office of the Governor
State Agencies
Programs and Activities:
Fuel Emergency Fund
Coal Policy Task Force
Division of Budget and Management
Division of Policy Development and Planning
Special Assistants to the Governor
Division of Energy and Power Development (DCED)
Programs and Ac-tivities:
Residential Energy Conservation Program
Low-Income Weatherization (w/DOE)
Energy Research, Development and
Demonstration Projects
Institutional Buildings Grants Program
Residential Building Lighting and
Thermal Standards
REAA Grants Program
Appropriate Technology Small Grants
Program
Energy Field Offices and Education
Program
Energy Planning (Long-Term Energy Plan)
Division of Business Loans (DCED)
Alternative Technology Revolving Loan
Fund
Bulk Fuel Revolving Loan Fund
Residential Energy Conservation Loan Fund
2-?~
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APPENDIX 2-B (cont'd)
Alaska Power Authority (DCED)
Reconnaissance and Feasibility Studies
Power Project Loan Fund
Power Cost Assistance Fund
Rural Electrification Revolving Loan Fund
Energy Program for Alaska (Power Development Fund)
Legislative Grants for Power Development
Alaska Public Utilities Commission (DCED)
Department of Na~ural Resources
Department of Administration
Alaska Energy Center
Alaska Council on Science and Technlogy
Northern Technology Grants Program
Departmen.t of Community and Regional Affairs
Bulk Fuel Storage Grant Program
Legislative Grants for Rural Village
Electrification
Coastal Energy Impact Program
Department of Transportation and Public Facilities
Activities:
Energy Audits of State Buildings
Energy Planning
Energy Projects
Department of Health and Social Services
Energy Assistance Program
Department of Military Affairs
Emergency Resonse Program
Office of Mineral D~velopment (DCED)
Office of Special Industrial Development (DCED)
Alaska Royalty Oil/Gas Development Advisory Board (DCED)
Department of Environmental Conseryation
waste Oil Utilization (funded by EPA)
Oil Pollution Control
Management and Technical Assistance
Program
Alaska Oil and Gas Conservation Commission
Alaska Renewable Resources Corporation (DCED)
Alaska Renewable Renewable Resources
Development Fund
Alaska Renewable Resources Investment
Fund
Alaska Renewable Resources Permanent Fund
University of Alaska
Department of Fish and Game
Oil Spill Response Team
Habitat Protection
Pipeline Surveillance Program
Department of Revenue
Investment of State Energy 11oney
Busine~s Energy Conservation Tax Credit
Alaska Gas Pipeline Financing Authority
Priyate Non-Profit Activities
Rural Community Action Program
Rural Weatheri~ation Program
Fuel Loan Program
2-29
SECTION 3
REVIEW ANP ASSESSMENT OF
ALASKA'S POWER PROJECT
' -DEVELOPMENT PROGRAM
INTRODUCTION
The power supply planning process in Alaska has been evolv-
ing rapidly since the creation of the Alaska Power Authority.
Changes in the process have been imposed legislatively and
internally, and the changing economic parameters which affect any
power supply planning process s~em even more extreme in Alaska
than in the lower 48 states. The power supply planning process
which precedes the selection of a specific power project or set
of projects for development represents a series of decisions
which take place over several years. Therefore, the problems
identified with a specific project development may be based on
decisions born from a power supply planning method or criteria
which is no longer used. In many cases in power supply planning,
the decision making criteria and methodologies vary significantly
over time, but the implementation of the plans resulting from
past decisions live on based on the momentum provided from the
previous decisions.
The following analysis of the power supply planning process
attempts to address this issue in light of the ever changing
power supply planning environment experienced in Alaska. While
there are some alternative approaches which would improve the
power supply planning process in Alaska, much of the controversy
surrounding such planning decisions is the result of decisions
and commitments made in recent years from planning work
conducted several years ago. This analysis attempts to
differentiate between past planning problems which manifest
themselves in current power supply plan implementation
controversy, any ongoing planning activities which could benefit
from revision to avoid future planning, and implementation
problems.
3-1
Since the Authority procedures have been changing
substantially, even as this report has been prepared, some of
what could be considered criticisms of the process may no longer
apply to current or proposed planning prQcedure and policy. One
of the objectives of this evaluation is to identify current
problems which resulted from past planning methods which have
been abandoned by the Authority for new procedures.
POWER SUPPLY PLANNING
Power supply planning is best ~hought of as a nprocessn as
opposed to a single task. The product of this_process is nA
Power Supply Plann spanning a period of time into the future.
The length of this period is a function of a number of factors,
including the lead time required for generation additions, but
most often covers ten to twenty years.
Once a power supply plan has been developed, it must be
periodically updated. In other words, the process is a
dynamic one. It is not that a new power supply plan is
periodically published, but rather that it is periodically
updated and extended into the future.
The process used to develop a power supply plan at any level
of complexity,·whether it is for an individual village, an urban
utility system, an interconnected utility grid or a geographic
region involves a series of interrelated evaluations and analyses
which ultimately lead to the development of power projects to
meet the electrical loads of the planning area.
In this section of the report, the planning process and
methods used in Alaska to identify power supply needs and to
select projects for inclusion in a power supply plan are identi~
fied and evaluated. The objective of this evaluation is to
identify the strengths and weaknesses of current power supply
planning efforts and to compare these practices with alternative
approaches. To provide a background for evaluating the
current planning process, a description of the generic steps
included in any power supply planning process is provided. The
current practices of power supply planning in Alaska are
3-2
summarized, using examples of the planning which has preceded the
current development of some specific power projects in Alaska.
This review of planning activities and the decision making
process focuses on the difficulties encountered by the Alaska
Power Authority, electric utilities, the State ·Legislature, and
other participants in the process. The review includes a
description of alternative methods for power supply planning
which could be considered to remedy the current power supply
planning problems. When applicable, effort has been made to
differentiate between planning considerat~ons in the Railbelt
region as compared to other areas of the State.
General Steps in Power Supply Planning
Although the complexity of the process may vary depending
upon the size and diversity of the utility system or geographic
area involved, there is a general progression of analyses which
should occur in developing and updating a power supply plan. The
following describes a "typical" power supply planning process as
a basis for the evaluation of the power supply planning process
in Alaska.
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The process generally requires:
Identifying the study area to be included in the power
supply plan
Projecting the future electrical power requirements
Establishing policies and criteria as a basis for
selection of alternative energy resources and
technologies to consider for meeting the projected
electrical power requirements
Evaluating the relative availability and desirability
of alternative power resources, and identifying
specific resource alternatives for which detailed
feasibility studies will be undertaken
Conducting a detailed feasibility analysis for projects
found promising at the reconaissance level stage
Selection of preferred projects from among the projects
found feasible for authorization for development to
meet projected needs
Securing final approval.for the supply plan and
individual project development
3-3
This process is shown graphically in Exhibit 3-1. The follow-
ing briefly describes the general types of activities and consider-
ations which comprise each major step of a power supply planning
process.
Definition of Study Area
The first step in the power supply planning process is to
define the study area. The definition of a study area includes
geographic, demographic, and utility system considerations.
Depending upon the scope of the planning process, the study area can
be a single utility system, a group of interconnected utility sys-
tems, or a geographic area which includes separate utility systems
which potentially could be interconnected with expansion of the
transmission system. The extent to which currently independent
utility systems are considered in a study area is dependent upon the
transmission distance between the system, their current size and
prospects for future growth, and the relative cost of power among
the systems.
The selection of the study area to be included in a power
supply plan is critical for forecasting of electrical load require-
ments. Furthermore, since the cost of power can differ signifi-
cantly between utility systems, the economic basis for evaluating
alternative power resources is dependent upon the systems to be
served by generation resources in the power supply plan.
Load Forecasting
Prior to determining which power projects should be
evaluated and implemented, the anticipated electrical loads of
the selected study area must be projected. A variety of fore-
casting methods can be used to project power requirements. The
complexity of the forecasting tools used to project power
requirements depends upon the complexity of the system and the
level of accuracy required. The level of detail which should be
considered depends on the availability of energy use, demographic
and economic data for the study area. Because of data
3-4
•
limitations and practical considerations, the rigor of load
forecasting for the Railbelt utilities is likely to exceed that
used for the bush communities and less developed Alaska.
Once developed, load forecasts are used to establish the
amount of electrical capacity and energy required for the study .
area over the planning period. These total projected electrical
capacity and energy requirements are then compared to the amount
of capacity and energy which can be provided by existing power
resources over the planning period. It is against this
projection of aggregate power and energy requirements that the
need for new power facilities is evaluated. The extent to which
existing power plants are to be retired, whether due to age,
policy considerations or economic obsolescence, directly impacts
the estimated need for additional power resources.
Policy and Criteria for Power Supply Plann~ng
A key element to power supply planning is establishing
policies and criteria for selection of alternative energy
resources, technologies and specific projects for inclusion in a
supply plan. Such policies and criteria can also impact load
forecasting. For example, the cost of power from power.supply
alternatives will impact load projections due to pricing effects
on demand for power.
The type of policies and criteria which most affect the
decisions on the facilities to be included in a supply plan
evaluation are (1) the degree of preference for specific types of
projects such as renewable energy resource projects, (2) power
cost limitations (short and long term) placed on alternatives,
(3) environmental constraints, (4) the ecoriomic criteria used to
compare alternatives, (5) financial limitations, and (6) the
availability and location of_resources. All of these factors are
considered either explicitly or implicitly in the selection of
resources for consideration in the supply plan and during the
selection of specific projects for authorization for development.
3-6
Review of Energy Resource Alternatives
After adopting a load forecast and establishing a set of
policies and criteria for power supply planning, the selection of
the alternative types of power supply projects and identification
of specific projects for ·inclusion in the supply plan can begin.
The general steps for this portion of the evaluation include:
Generic Assessment
A generic assessment is conducted to identify preferred
commercially available technologies and physically available
energy resources in the planning area which could be
developed within the planning period under consideration.
Such an evaluation includes a generic (as opposed to site
specific) evaluation of the cost of power from a "typical"
project using the various technologies or fuels, status of
commercial operation of such projects, environmental
considerations, and general availability of the required
resources in the study area.
Reconnaissance-Level Study
A reconnaissance-level study to identify the potential
for development of the preferred generic types of power
projects. believed to be available in the planning area is
then undertaken to narrow the options for supply alter-
natives to those with the best prospects for feasibility.
The product of this analysis is the identification of
specific projects which appear worthy of more detailed
evaluation.
Ranking of Alternatives
The ranking of alternatives which are found to be
promising in the reconnaissance level studies establishes a
basis for determining which projects should be studied in
more detail.
3-7
Detailed Feasibility Assessment of Alternatives
Detailed feasibility studies are performed to further
evaluate the promising projects identified during the
' -
reconnaissance study. The purpose of these studies is to deter-
mine which of the prospective projects meet the evaluation
criteria and deserve to be considered for inclusion in the supply
plan. The feasibility study results are then used to make a
final ranking of projects. This evaluation of projects considers
the anticipated schedule for development, method of financing,
and the proposed market for power from the project.
Selection of Projects for Recommendation for D~yelopment
After ranking those projects found preferable and feasible
within the policies and evaluation criteria established, the
"pool" of feasible projects is evaluated in terms of their
ability to operate as an augmentation to the existing utility
system to determine which "mix" of projects results in the most
favorable supply plan. In the case of evaluating small village
energy supply options, this evaluation is often reduced to
qomparing one or more hydroelectric or cogeneration (waste heat
recovery) project alternatives with continued or expanded-diesel
generating projects. Those projects with the best combined
characteristics are then tentatively selected through a screening
process to develop an integrated plan for implementation of
projects over a designated period. Alternative or "second best"
projects or groups of projects are also identified.
If the power supply plan is for a sufficiently large study
area that several projects will be required to meet the projected
power resource requirements over a 10 to 20 year planning period,
the list of preferred projects will usually include some projects
for near term development and other promising projects for later
implementation to meet longer term needs.
3-8
Authorization for Design and Construction
Although a list of preferred projects in an integrated plan
has been developed, this does not necessarily infer commitment.
The preferred projects with the earliest dates of implementation
ar~ reviewed in more detail based on financing plans and updated
economic constraints. If this review confirms the relative
economic priority of the most promising projects, a recommenda-
tion is made for licensing/permitting and final design. Assuming
no "fatal flaws" are uncovered during final design, each project
is reviewed after design is completed for construction authoriza-
tion, assuming project financing can be arranged. A final econo-
mic evaluation is conducted and once authorized, the project
proceeds to bid and construction.
Updating Power Supply Plans
The power supply plan must be reviewed periodically to
ensure that projects scheduled for implementation late in the
planning period remain feasible and preferred over the
alternatives. This process involves updating load forecasts and
re-evaluating the feasibility of projects previously identified
for deferred development to meet longer term forecasted needs.
In addition, in the interim, periodic re-evaluation of the avail-
ability of additional alternatives can be conducted to update the
list of preferred projects.
CRITIQUE OF ALASKA POWER SUPPLY
PLANNING METHODS
Based on the steps outlined above, the following is a review
of the methods which have been or are currently used in power
supply planning at the State level in Alaska. A general observa-
tion, which is a recurring finding in the review, is that the
planning conducted in Alaska at the State level has been more
"project" oriented and not utility system or planning area
oriented. There are other contributing factors, but this
3-9
"project-by-project" evaluation and approval can be linked to a
number of the past weaknesses in the.power supply planning process.
On many of the projects which are in the more advanced
stages of project planning, the evaluation of alternatives has
been largely limited to a comparison of one or more projects ~o
the "preferred alternative" after questions have been raised
regarding the feasibility of the preferred project. Many of
these projects, such as Lake Tyee, Bradley Lake, or, more
notably, Susitna, are projects for which substantial analysis had
been conducted by the Corps of Engineers, the u.s. Department of
Energy, or others in a project-specific analysis, not as ·part of
an integrated power supply plan. The planning momentum created
by such previous analyses tends to establish these projects as
the "base case" in an analysis of any alternatives. This fosters
a continued project-oriented planning approach for the market
area served by the project. To a large extent this situation is
unavoidable.
Many of the recent planning and evaluation efforts
undertaken by the Authority where past studies have not created a
designated "preferred project~ have been more power supply ~
oriented rather than project oriented. Mention .is made of some
of the problems which have surfaced with the project-oriented
approach on some of the long-standing projects referred to herein
in an attempt to identify the source of some of the controversy
surrounding these projects. These examples also serve to
identify some of the positive steps the Authority is taking in
recent planning efforts and to include some advantages of
alternative approaches which could be considered by the
Authority.
The following describes the strengths and weaknesses of the
current practices for each of the major stages in the planning
process, and identifies some alternative approaches for
consideration. Where possible, this discussion attempts to
differentiate between past planning activities and recent changes
in planning approaches by the Authority.
3-10
Power Supply Planning Areas
The extended Railbelt Region has been recognized as a power
supply planning area. The Authority and the Alaska Power
Administration have also looked at other areas of the State in
terms of power supply planning. However, a more formalized power
supply planning process requires the definition of other areas in
the State for pl.anning purposes.
The primary criteria for designation or definition of a power
supply planning area is either existing interconnections or
indications that interconnections might at some time in the future
be feasible. We have discussed this with Authority staff and at
our request they have indicated that the following areas might very
well be designated as power supply planning areas:
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South~ast Alaska including Ketchikan, wrangell,
Petersburg, Juneau, and Skagway, as well as Prince of
Wales Island and Sitka
South Central Alaska which would generally encompass the
area presently known as the extended Railbelt
Barrow-Atkasuk-Wainwright
Kotzeb~e-Lower Kobuk Region
Seward Peninsula
Bristol Bay-Bethel
Kodiak Island
Designation of these or other areas as power supply planning
areas would not reflect a commitment for the construction of
interties. Rather, it wou~d provide a fr~mework where the
construction of interties would be evaluated periodically as
alternatives to constructicin of. smali ~e~~ra~ion facilities to
serve individual loads within the area.
Other areas of the State, particularly the bush villages,
would have to be dealt with on an individual basis as is the
current practice.
3-11
Load Forecasting -Railbelt Region
The level of complexity of forecasting requirements and
availability of data for accurate forecasting differs signifi-
cantly between the Railbelt Region, southeast Alaska, and the
bush communities. The review of the forecasting of electrical
loads in the Railbelt Region is discussed separately from fore-
casting for the bush communities and Southeast Alaska.
Current Practices -Forecasting for the Railbelt
The most extensive effort to date to forecast electrical
loads in the Railbelt Region is that which was recently C?mpleted
as part of the Railbelt Alternative Study. This effort can be
characterized as a "top-down" type of forecast where aggregate
regional economic and demographic factor~ were considered in an
energy end-use prediction model to forecast total subregional and
aggregate reg~onal electrical demands. One of the major weak-
nesses of the forecast is that it is not built on forecasts of
the anticipated load growth for each of the respective utili-
ties.W
Due to the lack of an agreed upon Railbelt area forecast,
the Authority is in the position of having to reevaluate the
potential alternative demand scenarios in the evaluation of each
potential power supply project in the region--most notably the
Sus i tna Project.
Assessment of the Railbelt Forecasting Process
The forecasting work being conducted for the Division of
Energy and Power Development, is not structured for use in power
supply planning. It appears that regional data is being aggre-
-
gated without consideration for (or at least without presenting)
the individual projected loads of each utility in the region.
This makes involvement, critique, and utilization of the forecast
by the individual utilities difficult. This generally precludes
taking advantage of each utility's knowledge of their own system
3-12
trends and operating characteristics in judging the reasonable-
ness of the forecast.
Additional uncertainty has been added to the forecasting
process by the past treatment of the Anchorage-Fairbanks intertie
as a variable.ll/ The previous lack of a decision on this inter-
connection has caused great uncertainty about near-term intercon-
nected demand for the region. This policy-related issue is
addressed in more detail later.
The forecasting effort in the Railbelt has diverted efforts to
conduct forecasting in a manner whiqh would be more compatible with
power supply planning needs. Due to the major funding commitment
to the Railbelt Analysis forecast and the expectations of that
effort, other major forecasting efforts to support the Authority's
power supply planning were not undertaken.
The Division of Energy and Power Development is required to
prepare a long term energy plan, of which load forecasting is a
part. Preparing a totally new forecast for the entire State of
Alaska annually is nearly impossible. Insufficient time exists for
evaluating changing economic conditions, policies, and demographics
to allow for evaluation, presentation of preliminary results and
constructive, participative critique by the parties involved.
Forecasting for the Long Term Energy Plan under-emphasizes
forecast assumptions and results for the near-term, 5-io years.
This reduces the ability to review short term forecasts. Periodic
review of forecast accuracy is an important element in any long
term forecasting program.
Alternative Approaches to Railbelt Forecasting
Any renewed effort to prepare a forecast for the Railbelt
utility systems will be·out of phase with-much of·:the project
specific evaluation procedures and authorization decisions cur-
rently before the State Legislature. However, decisions regar-
ding system interties, financing of Susitna and other projects,
project operation and dispatching, and other major power supply
planning decisions which remain unresolved are dependent upon
load forecasts which provide sufficient electrical load and load
characteristics data to enable such planning to occur. The
3-13
following identifies some alternative approaches and considera-
tions for preparing such forecasts:
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The Railbelt Alternative Study included an analysis of
a set of consistent economic assumptions for applica-
tion to the total market area of the Railbelt study
area. However, ~here has been disagreement as to
whether the range of alternative demand forecast
scenarios has encompassed the full range of potential
demand scenarios. In addition, as presented in the
Railbelt Study report, the forecasting assumptions
utilized do not appear to address differing demand and
energy end-use assumptions between the major utility
areas in the Railbelt areas in a manner which allows
each utility area to provide a planning critique of the
validity of those assumptions in its service area.
This information may be available, and may be incor-
porated in the model, but the forecasting results do
not appear to be presented in a manner which allows
individual utility review and critique.
The assumptions on the extent of interconnection between
the various systems could be established in advance.
The Anchorage-Fairbanks intertie is now considered to be
a planned project, eliminating one variable from the
forecast assumptions which complicated some of the
earlier planning efforts.
The forecast period could be separated into short,
medium, and long term forecasts (as an example, 5, 10
and 20-year planning periods). Planning and
forecasting assumptions could consider the relative
uncertainty of knowledge of the factors which influence
energy costs and demand over these different planning
periods. This is particularly useful if near and
intermediate term power costs are used as one parameter
in deciding among power supply alternatives. The
forecasting effort currently undertaken by the
Authority could be easily adjusted to develop
forecasting assumptions which coincide with near,
medium, and long term planning periods.
Individual utility_ system service areas could be
evaluated separately prior to and after aggregation of
lo~-d forecasts into forecasts-of-in·terconec~ed systems.
This would allow identifying load implications of
specific utility service area economic development
scenarios, such as new industrial projects under
consideration, in much the same manner as has typically
been done for some of the isolated systems in southwest
and southeast Alaska. Regional aggregate forecasts can
still be generated while providing utility system or
sub-area specific projections which enable critical
review and use by the individual utilities. If
individual utility service area loads and resources are
3-14
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not addressed in the demand forecasts, future rate
setting and power allocation must treat the entire
Railbelt as a homogeneous utility service area. Since
most of the Railbelt utilities have existing resources
of their own which differ in average energy cost by
utility, the impact of one or more regional projects on
average cost of energy to each utility will differ. It
is unclear how an aggregated ~nalysis of Railbelt
regional demand can address this issue.
Seasonal and time of day load diversity could be
addressed on an aggregate and individual utility basis
to allow for more specific evaluation of rate making
and power marketing alternatives.
A base forecast could be established and updated on a
periodic basis (such as every two or three year~) to
provide an evolving planning tool for use in power
supply planning. More frequent changes could be made
on an exception basis in the event of major rev is ions
in planning assumptions, but annual revisions on a
regular basis make planning complicated.
Load Forecasting -Outside the Railbelt Area
Forecasting for bush communities and other Alaska communi-
ties, such as native settlements or communities which exist
primarily due to industrial operations (fish canneries or lumber
mills, _for example), presents different problems from Railbelt
system forecasting. Energy end use patterns, demographics, and
price elasticity, among other factors, are clearly substantially
different for bush communities as compared to the Railbelt. The
availability of historic and current data regarding parameters
which impact energy use and demand can preclude the use of sophis-
ticated econometric forecast models. The following describes
some of the strengths and weaknesses with the manner in which the
Authority has addressed these problems.
I . ' .
Current Practice -Forecasting Outside the Railbelt Area
The constraints associated with forecasting for the bush
communities and the lack of data on which to base forecasts have
generally been acknowledged in the forecasting efforts conducted
to date for these power market areas. Forecasts for bush commu-
nities are often criticized simultaneously by reviewers as being
3-15
too high and as too low by local citizens with a more optimistic
outlook on local economic growth.
strengths of Current Forecasting Outside the Railbelt Area
Strengths of the current practice include the following:
0
0
0
Current and past forecasting efforts for these communi-
ties have recognized the constraints to accurate fore-
casting. Where possible, local utility operators
appear to have been relied upon for input concerning
historic and projected energy use patterns. Attention
has focused on industrial or commercial development
which can greatly influence demand.
The effects of the Power Cost Assistance Program
applicable to many of these areas and the potential for
future~conversion toJelectric heat has been addressed
at least qualitatively, if not quantitatively, in
preliminary demand forecasts conducted as part of
village reconnaissance studies.
Interconnection opportunities have also been more regu-
larly addressed in recent studies of bush communities.
In some instances, significant changes in industrial/
commercial or government facility operations occur
during the course of project planning. This can
require reconsideration of interconnection alternatives·
at untimely points in the power supply planning process
for a specific community or region. The Authority has
shown willingness to incorporate such changes in their
planning process (see discussion of Appendix 3-C
regarding reconsideration of adding Thorne Bay to an
interconnected system for the Black Bear Project on
Prince of Wales Island). More recent planning efforts
have focused mo~e extensively on interconnection alter-
natives and "market area" analyses in bush community
studies (such as in the July 1982 Bristol Bay Regional
Power Plan Detailed Feasibility Analysis).
weaknesses of Current Forecasting Outside the Railbelt Area
The major weakness in the forecasting effort in the bush
communities and Southeast Alaska is the manner in which the
forecast is used in planning. Examples include:
0 Forecast ranges continue to be a large variable in the
power supply planning process beyond the stage where a
final project has been selected for implementation.
The forecast is not consistently used as a basis for
establishing a reasonable range of electric needs.
3-16
0
0
Instead, a project is often selected when alternative
forecasted power needs predict a potentially wide
range. Perhaps more importantly, the range of
alternative forecasts used at reaconnaissance level or
even detailed feasibility assessments does not always
encompass more conservative demand levels considered
more likely by some reviewers, or higher demand levels
consider•d likely (or hopeful) by local citizens of the
communities. To the extent that the potential range of
energy demand addressed in Authority studies does not
cover lower or upper limits considered possible by
reviewers, basic questions regarding the preferability
of a selected supply plan may create unwarranted
controversy during later project planning activities.
Consideration (and perhaps early but well justified
dismissal) of lower or higher ranges of energy demand
projections at the early planning stages could help
reduce untimely requests for consideration of alterna-
tive demand scenarios by project reviewers at the
project authorization phase.
Two major policy issues--the long term use of the
Power Cost Assistance Program and the conversion to
electric heating can greatly impact forecasted electric
demand. Policy decisions on whether to plan for these
programs were not resolved before forecasts were
developed. As an example, forecasts with
and without conversion of electric heating often
continue to be addressed as equally viable 1 alternatives
well into the stage of alternative project selection
and even project authorizations. The analysis of the
Old Harbor project on Kodiak and the Silver Lake
Project in Cordova are examples of the former and the
Tyee Lake Project analysis is an example of the latter.
The result is that the range of alternative forecasted
demand can be so high that the value of the forecast in
power supply planning is questionable.
A related problem exists in forecasting for those areas
where interconnection of currently independent communi-
ties is a possibility. Forecasts can vary substantially
depending upon the planning area considered in a study.
In several cases, a specific project has been selected
for development, and authorization decisions are being
based on project feasibility with and without intercon-
n§!C_tion of ya_rious neighboring interconnected loads. The
forecasted load associated with the alternative plan-
ning areas can differ substantially, causing wide
variations in estimated average annual energy costs
from hydroelectric projects. The December 1981
Statement of Findings and Conclusions analysis of the
Tyee Lake project is an example of this situation.
Analyses for the Black Bear Project on Prince Wales
Island is another. The Bristol Bay study mentioned
above is a good example of the approach to evaluating
bush community alternative market areas prior to selec-
tion of specific projects for development.
3-17
Alternative Approaches to Forecasting
Outside of the Railbelt Area
As in the Railbelt area, many of the project development
decisions have already been made despite some of the problems
with the manner in which forecasting has been used in the power
supply planning process. In those situations where planning has
not progressed to this stage, or reconsideration has been
requested by the Legislature, the following provides some alter-
native approaches:
0
0
Alternative market areas can be evaluated early in the
forecasting process using reconnaissance level
interconnection cost estimates to determine the
likelihood of including communities in an inter-
connected system. Alternative forecasts using
different market area assumptions, where applicable,
can be developed and used to screen power supply alter-
natives at the reconnaissance level stage.
Studies conducted by and for the Authority have generally
incorporated alternative and most likely energy demand
s~enarios at an early stage in the planning process.
Public input has also been solicited as part of the
preliminary demand forecasting conducted during recon-
naissance studies for bush communities. However, if the
preliminary evaluation of the feasibility of a specific
alternative energy resource or project available in the
market area is particularly sensitive to load growth
assumptions, the effect of alternative demand forecasts
could be evaluated at the reconnaissance level stage.
The purpose of such an evaluation would be to see if a
change in market .area definition or a demand sensitive
policy implementation (e.g., power cost assistance or
electric heat conversion) would result in a different
ranking of all alternatives. This level of evalua-
tion would not be necessary in all cases. To the
extent that bush communities in a study area have a
possibility for interconnection, or there are factors
which could·substantially alter power.demands in an
area, these alternatives should be addressed at the
reconnaissance level stage.lj/ This is discussed in more
detail later.
Power Supply Planning Policy and Evaluation Criteria
An important element of power supply planning and the
evaluation of alternatives to meet identified needs is the policy
direction that provides a basis for the planning work and for the
,•
3-18
evaluations in the reconnaissance and feasibility study phases.
The portions of the legislation creating the Authority and
establishing the Energy Program for Alaska set forth certain goals
or objectives established by the Legislature. One ar~a that we
believe deserves additional policy consideration relates to the
utilization of fossil fuels, particularly oil and natural gas; as
boiler fuel. Utilities within the State, in many cases, have no
alternative but the construction of diesel generating units.
However, in some areas of the State, particularly the Railbelt
Region, utilities continue to construct natural gas-fired units.
We believe that the Legislature should address itself to the
question of establishing a policy in this area. If, in fact, the
State establishes to minimize or eliminate where possible the use
of these fossil fuels for boiler fuel, the importance of developing
large hydroelectric projects would be emphasized.
As in the case of power supply plans, the P?licy directions
provided, for both the overall guidance of the power supply plan-
ning process and with respect to the methodology utilized in that
1 process, must also be periodically reviewed and updated. In this
regard, the responsibility for monitoring the overall policy area
might be assigned to DEPD with the charge that they would periodi-
cally report to the Legislature with recommendations for any indi-
cated changes. Likewise, the Division of Budget and Management
might be charged with the responsibility of periodically reviewing
analytical methods utilized in feasibility studies and the develop-
ment of financial plans to provide the Legislature with recommenda-
tions for policy direction in these areas. In the development of
policies for the guidance of power supply planning and development
it must be recognized that because of the diversity between the
various areas of the State it may be that som.e .policies have to be
promulgated on an area specific basis "as" "oppo"s-ed "to a statewide
basis.
Current Policy and Evaluation Criteria
Prior to evaluating alternative power technologies and
specific power supply projects, the planning objectives and the
criteria used to evaluate projects must be established. These
3-19
policies and criteria are reflected in the Authority's project
evaluation procedure to some extent, since this procedure is used
to select projects for development. Simply stated, the Authority's
goals in power supply de.velopment are to:
(1) Maximize net power project economic benefits tempered
by environmental, socioeconomic and public preference
constraints, and ·
(2) Intervene in financial markets to permit "worthy"
projects which may not be capable of being financed using
traditional £inancing methods to be developed free of the
traditional financing constraints~
To implement these objectives, the primary criteria used to
approve projects for development is a life cycle cost analysis
comparing the present value of project costs over tha project life
to the present value of the costs of a base case thermal al terna-
tive. The planning period for evaluating the life cycle present
value of project costs is also established as a period equal to the
life of the project with the longest commerical life of those under
consideration. Since most Railbelt and Southeast Alaska projects
under consideration for implementation are hydroelectric projects
and the alternatives are oil-and gas-fired or coal-fired plants,
the 50 year life of the hydroelectric project is usually used as
the period over which the present value analysis is made.
A 50-year present value analysis to compare projects using
fuel which escalates in price with projects with no fuel costs
will often favor the project ·..vhich does not use fuel if suffi-
ciently high levels of prolonged real escalation of fuel costs
are used in the analysis. The Authority has utilized fuel esca-
lation sensitivity analyses in their final feasibility studies.
The use of the analyses by the Authority in the final decision
process is unclear, however.
For example, in the Tyee project analysis, the Authority's
Statement of Findings and Recommendations (12/2/81 Update) ana-
lyzed project scenarios using zero, 2.6 percent and 3.5 percent
real fuel cost escalation. The report mentions that if fuel
escalation rates are significantly lower than the annual 2.6
percent real escalation rate for a twenty-year period, the Tyee
project is economically inferior to continuing diesel generation.
3-20
The analysis of lower fuel cost escalation has been performed and
conclusions drawn, but it is unclear how this risk of lower
future diesel generation costs is factored into the decision
.making process. At issue may be the presentation of the results
of the analyses and not a question as to whether the analyses
were performed.
The strong focus by the Authority on the 50-year present
value life cycle cost analysis as the critical criteria for
determining project feasibility de-emphasizes the risk that
actual fuel cost escalation rates may not meet the expectations
of the "most likely cost projection" (even though the analyses
generally include an evaluation of that risk). If the present
value analysis shows the existing thermal case to be preferable
to, for example, a hydroelectric alternative, even when moderate
or high fuel escalation rates are utilized, the Authority has
appropriately eliminated the hydroelectric project from further
evaluation. There are several examples of such findings by the
Authority.
The risk of over-estimating fuel cost escalation using a 50-
year present value analysis (where costs are held constant after
20 years) as a decision criteria becomes an issue when the 50-
year benefit/cost ratio of the hydroelectric project to the base
case thermal alternative is near unity, using a fuel escalation
scenario which assumes substantial continued real fuel cost esca-
lation. This is often (but certainly not always) the situation
when a hydroelectric project is determined to be feasible in
Authority studies. This is also usually the situation in which
there is controversy regarding the advisability of proceeding
with development of the hydroelectric project.
In a situation such as this, the true cost of power from the
hydroelectric project is generally projected to substantially
exceed power costs from the thermal base case alternative for
several years of operation. This cost of power comparison is now
being included in Authority studies. However, it is not clear
that past decisions to develop a project with, for example, a
benefit cost ratio of 1.15 assuming 2 to 3 percent real oil
escalation for 20 years has given full consideration to the risk
that the preferred project would continue to have power costs in
' 3-21
excess of the base case thermal alternatives if the real rate of
final cost escalation were, for example, 1 to 1.5 percent
annually during the same period.
Recent studies by the Authority appear to be addressing this
issue in re-analyses of feasibility studies to consider this risk
and the risks of overestimating power demands where the results
using the present value life cycle cost criteria alone do not
provide a conclusive test of feasibility. However, there does not
yet appear to be an agreed upon "standard" procedure or criteria
to augment the present value cost method when that method proves
to be of limited value as a single decision criteria.
The uncertainty of price elasticity impacts on energy demand
caused by the State subsidy program complicates project evaluation
in areas where a subsidy is used. The uncertainty caused by such
subsidy is inversed if the subsidy encourages conversion from
heating with fuel oil to electric space heating. This issue is
treated as a variable in some project specific evaluations. When
reviewing the feasibility of hydroelectric projects outside of the
Railbelt area, the extent to which the study area population
converts from fuel oil heating to electric heating can be one of
the largest variables in predicting average energy costs from a
hydroelectric project as compared to thermal generation sources.
Alternative Approaches to Establishing
Policy and Evaluation Criteria
The use of the present value life cycle cost as the primary
evaluation criteria for power supply planning is, in itself, a
major policy decision. As discussed above, where the present
value cost of the selected alternative plan or project is vastly
superior to the base case thermal alternative, this criteria may
be a reasonable decision criteria. Even projects with substan-
tially lower present value life cycle cost often result in high
near to intermediate term power costs relative to thermal
generation. Using present value life cycle cost as the sole
economic test assumes that it is an established and accepted
policy that the substantial financial resources of the State of
Alaska should be used to help alleviate the "market shock" of
3-22
near term hydroelectric project power costs, through subsidy or
savings.
Where the difference between present value costs of alterna-
tive projects is small, if a hydroelectric or other renewable
energy project (or set of projects) is selected over the base case
thermal alternatives, there is an inferred policy behind such a
decision. The inferred policy ii that the desirability of using
renewable resources and protecting against incurring the penalty of
high escalation of fuel costs is worth the risk that the future
fuel costs are lower than those assumed in the scenarios used as
the basis for a decision to develop the hydroelectric or other
renewable resource project. If this is not a current or desired
policy of the State, another form of economic evaluation criteria
(such as the criteria described in the discussion of reconnaissance
studies later in this report) could either replace or augment the
present value life cycle cost criteria.
The Authority has struggled with this issue on projects
where the present value cost of what has come to be the preferred
alternative is not clearly economically superior under the full
range of reasonably possible projected fuel costs. (The deci-
sions in such situations are further complicated when relative
present value life cycle costs of alternative projects or plans
are highly sensitive to alternative demand forecasts.) This has . '
been a decision-making problem on projects such as Lake Ty.ee,
Black Bear, to some extent on Bradley Lake, and, on a much larger
scale, for the Susitna Project.
Due to the controversy regarding decisions on these projects,
the Authority has been appropriately conducting additional analyses
of these projects to consider alternative fuel cost and demand
assumptions. Nominal cost of power analyses have also been added
to the ninflation free" analyses used in the standard Authority
procedure. The Authority's exhibited willingness to be flexible
and use different economic evaluation methods and criteria as
needed shows a practical approach to the decision making process.
These alternative evaluation procedures which have been used by the
Authority on a case-by-case basis may ultimately lead to revising,
or at least augmenting the present value life cycle cost evaluation
method and decision criteria in the Authority's standard procedure.
3-23
Discussions of the reconnaissance and detailed feasibility study
stages of the power supply planning process (in later sections of
the report) include descriptions of some alternative evaluation
methods and criteria which could be considered by the Authority for
use in augmenting the present value life cycle cost procedure.
Examples of other policy decisions which could r~duce the
variables in power supply planning in general and project evalua-
tion in particular could include:
0
0
0
A policy on the acceptability of displacing fossil fuel
sources for space heating with electric heating from
renewable resources. It is a reasonable policy to
encourage the conversion from fossil fuel-fired space
heating to electric heating supplied from power plants
using renewable energy resources if the electrical power
from renewable sources can be provided on a cost
effective basis. The issue becomes complicated in the ·
instance where (1} conversion to electric heating in a
market area is necessary for a hydroelectric project to
have a significantly lower present value life cycle cost
over thermal alternatives, and (2} substantial State
subsidy is needed to make the power from such a project
marketable for several years of project operation. This
appears to be a policy issue faced on several projects.
A requirement to evaluate the integration of indepen-
dent utility systems as a prerequisite to evaluation of
specific power projects within a given utility system.
This appears to be an evolving, if not a formally
adopted policy utilized in recent studies conducted for
the Authority (the Bristol Bay Regional Power Plan and
the Bethel Area Power Plan feasibility assessments are
examples of a major effort to consider the impacts of
potential interconnection options in evaluating the
economic feasibility power supply plan alternatives).
A preference for achievable conservation and
implementation of conservation projects prior to
commitment to power supply projects.
Each of these policy topics could be addressed on a geographi-
cally specific basis, a utility system .basis, or a statewide basis.
As an example, a decision could be made that natural gas or oil
will only be used in the Railbelt if there are no other alternative
sources, but that such a provision need not apply to other areas of
the State. The ~dvantage of establishing specific policies is to
reduce extensive re-evaluation of the issue on a project-by-project
basis.
3-24
The alternative criteria which can be used to evaluate
supply plans and analyze the feasibility of specific project
alternatives is another planning consideration which can be estab-
lished in advance of power supply planning to be consistent with
established policies. These alternative evaluation approaches are
discussed in the section of the report ~n feasibility assessment.
Reconnaissance Evaluation
Recognizing that the power supply process addresses both the
"demand side" with the load forecasting functions and the "supply
side" with the resource development functions, the reconnaissance
evaluation is really the first step on the supply side. The load
forecast, together with a balancing of loads against existing re-
sources, indicates a potential need. The reconnaissance evaluation
is the first effort to identify alternatives to meet that need.
Once completed, reconnaissance evaluations for individual villages
or communities or for all or portions of power supply planning areas
must, as with the total power supply plan, be periodically updated.
The product of the reconnaisance study is a prioritized pool
of alternative projects to meet identified needs within the power
supply planning area. The reconnaissance study results are the
initial input to the feasibility study.
Current Practice
The methods and approaches used by the Authority, or which
were used by others in the past, to identify projects currently
under development by the Authority vary significantly. The
hydroelectric projects in advanced stages of development today
(des~9n or _construction) _ wt;r~ genE; rally those identified in the
u.s. Army Corps of Engineers statewide reconnaissance study or
other previous efforts to identify potential hydroelectric sites.
This effort was not part of a power supply planning process. Its
purpose was to identify specific projects. The availability of
this work effort undoubtedly helped contribute to what has
previously been a project-oriented power supply planning process in
Alaska.
3-25
In the past, due, at least in part, to this hydroelectric
project data base, many of the reconnaissance level studies have
focused on the feasibility of a specific project as the oasis for
evaluating other alternatives early in the study. Criticism has
been received at the State and local level in some cases that
insufficient consideration of alternative planning concepts (such
as interconnection or potentially lower or higher demand forecasts)
were considered as part of the study.l5/
This project-oriented approach is less prevalent in more
recent Authority studies. The Bristol Bay Regional Power Plan
study is an example. Although this study is more detailed than a
reconnaissance study, the "Interim Feasibility Assessment" (Phase I
of the Study) is much like an extensive regional reconnaissance
analysis. As with studies of other market areas, this study did
focus on the relative desirability of a single project, in this
case the Tazimina Hydroelectric Project, as compared·to a variety
of alternative projects. The Tazimina Project was identified as a
preferred project for the region in early studies of alternative
hydroel~ctric projects. It is therefore appropriate that one of ··.;.
the main objectives of the updated studies be to compare alterna-
tives to this project. One of the strongest features of the
Bristol Bay study is that it has considered a variety of alterna-
tives and combinations of alternative power supply resource to
the Tazimina Project before a major financial commitment was made
to develop that project. As a result, a wide range of alterna-
tives are being analyzed in a systematic planning approach to
consider regional market area needs. This study appears to be a
good model which the Authority can use in future analyses.
A large number of reconnaissance level analyses are being
conducted under the Village Energy Reconnaissance Program by the
Authority. This program includes evaluation of both direct
thermal application of energy and electric energy demand and
supply. It is about one-half completed with approximately 60
villages with populations in excess of 50 persons scheduled for
reconnaissance study next year. While considerable analysis will
be done as part of this proposed effort, the majority of the
areas in which significant electrical capacity is potentially
needed have already received some level of reconnaissance study.
3-26
As mentioned above, the procedures which are being used in the
recent Bristol Bay and Bethel Area studies represent substantial
improvements in the overall power supply planning approach. To the
extent that this approach is incorporated at the outset of future
reconnaissance studies, many of the previous problems encountered in
the planning process will be reduced. Therefore, the primary focus
of this review of the reconnaissance level phase of power supply
planning is to identify some of the weaknesses in past reconnais-
sance studies as a source of some of the difficulties currently
experienced in decisions on authorizing projects for design and
construction. These past problems are contrasted with some of the
recent improvements in the Authority's approach to supply planning
in an attempt to distinguish between residual problems from past
practices and suggestions for alternative evaluation methods to
augment the improved process now being used by the Authority.
A significant aspect of the Authority's reconnaissance stqdy
methodology is the use of the present value life cycle cost
analysis to evaluate alternative projects and select projects for
detailed feasibility analysis. This practice, which is the
Authority's method of meeting a legislative mandate to apply a
consistent evaluation procedure, is used throughout the feasibility
study and authorization phases of project evaluation. The
significance of using this economic evaluation criteria at the
reconnaissance level stage is described below. Since the use of
reconnaissance level studies has differed between the Railbelt and
other areas, these differences are described where appr~priate.
Strengths of Past and Current Practices
In Reconnaissance Studies.
The Village Energy Reconnaissance Program incl_udes most
of the appropriate considerations for such studies. The
concept of reviewing village interconnection potential and
evaluating ranges of demand forecasts are incorporated in the
studies to some degree. Of the studies and study summaries
reviewed, the studies recognize that there is likely to be
some impact on power demand in communities where the Power
Cost Assistance Program has been implemented. Presumably due
3-27
to the limits of the budgets of such studies, the reports
understandably treat this issue qualitatively.
The Authority's efforts to maintain consistency between
the-reconaissance studies are also appropriate. This allows
for consistent comparison of projects.
The Authority's wo·rk in securing local input to such
studies is also a strength.
weaknesses of Past Practices in Reconnaissance Studies
A review of the procedures .used and issues surrounding
reconnaissance level studies performed by the Authority
require a comparison of past practices with more recent
approaches used by the Authority. A further distinction must
be made between studies conducted for the Railbelt and those
conducted for bush communities.
The problems with reconnaissance analyses in the Railbelt
are primarily a function of the timing of the analyses of
alternatives relative to the advanced stage of planning for
the susitna Project. The Battelle study of the Railbelt
Alternatives is an extensive effort to evaluate alternative
power supply resources in the Railbelt area. A study this
extensive can be approached from several directions utilizing
a variety of techniques. Some alternative approaches to con-
ducting such an analysis are discussed in Appendix 3-B.
Regardless of the approach taken in such an analysis,
however, a major constraint to using the results of this study
is its timing. From a planning perspective, the analysis at a
reconnaissance level of any single project or group of
projects as alternatives to susitna faces the problem of
exceedingly disproportionate data bases upon which to make a
comparison. The Susitna Project enjoys the benefit of years
of environmental, engineering, and economic study. To compare
preliminary analyses of alternatives at a reconnaissance level
creates a natural planning and evaluation bias towards the
more extensively evaluated project.
This observation is not a criticism of the Authority nor
any of the organizations involved in the study and evaluation
3-28
of Railbelt power supply plans, it is simply a recognition of
the existing planning environment. The result of this
situation is that it is difficult to offer alternative
approaches to the evaluation of Railbelt power supply options
which would provide study results that would receive serious
consideration as feasible alternatives to Susitna.
In the reconnaissance evaluation of bush communities,
the problem of identifying service areas and preparing a
more complete list of alternatives for consideration is less
complex than in the Railbelt. Power Supply "systems" in the
bush are simpler and have fewer available alternatives than
Railbelt utility systems. However, the lack of a well
established data base for estimating energy use and little
previous analysis of available energy resources can make it
difficult to accurately evaluate energy needs and available
alternatives. (This is the primary reason the reconnaissance-
level study is needed.) In reviewing some of the completed
reconnaissance studies, the;possibility of regional power
projects supplying power to more than one village or commu-
nity is possibly being discounted too early in the process.
Since much of the regional or sub-regional power demand
picture is not known until after the reconnaissance-level
studies are done, it is difficult to make judgments on the
ability to develop sub-regional systems to supply power to a
group of the smaller villages until after the reconnaissance-
level studies are completed. This problem and some of the
recent Authority approaches to it are described under the
discussion of alternative approaches.
Since economic events (such as commercial facility
developments or closings) can significantly impact energy
demand at a village, ,it ,.may.be prudent .for the reconnaissance
studies to give special consideration to energy supply
projects which appear technically feasible. Past reconnais-
sance studies have noted that future increases in demand
beyond the projections used in the study could make some of
the larger projects (usually hydroelectric) feasible. Some
preliminary quantitative analysis of the rates of growth or
power demand levels necessary for the alternative project to
3-29
be economically superior would aid in identifying when a
future reevaluation of alternatives might be justified.
A problem common to all reconnaissance studies is the
State's policy of using present value life cycle cost as the
sole economic criteria for evaluating and comparing alter-
natives. The present value cost method is used by the
Authority to screen and rank alternatives at the reconnais-
sance study phase. If reconnaissance level study estimates of
the present value life cycle cost of a project vary greatly
from the cost of alternative projects, this finding may be
sufficient to recommend one alternative over another for
detailed evaluation. However, it is difficult to confi-
dently select between projects-whose present value life
cycle cost over a fifty year period are relatively similar.
The potential drawback to this evaluation approach as a sole
criteria is discussed in more detail in the section
pertaining to detailed feasibility studies.
Alternative Reconnaissance Study Approaches
One change which could be considered is to broaden the objec-
tives of the studies. This could be accomplished by incorporating
phased studies. First, an evaluation aimed at identifying
alternative and most likely study or service areas for interconnec-
tion could be conducted. In the case of isolated villages the need
for such evaluation would obviously be limited. This first recon-
naissance-level study could focus primarily on existing energy use
patterns and demand projections and availability of alternative
energy resources in the study area. Although it is appropriate to
identify and evaluate specific project alternatives at this stage,
the primary focus of this first phase of analysis would be as a
nscreenn to rank those villages or groups of villages where addi-
tional analysis of alternatives is warranted. This focus would
provide budget planning guidance for the Authority in establishing
future study priorities.
The Bristol Bay and Bethel area regional power plan approach
is a good example of the types of follow-up study that would follow
the reconnaissance level studies described above. In these
3-30
studies, the results of earlier reconnaissance studies were
reviewed to identify potential regional and sub-regional develop-
ment plans, and additional project concepts were identified and
evaluated in more detail. A similar approach could be applied to
the results of the reconnaissance studies which have been completed
(although there is not likely to be other bush areas with regional
development potential as extensive as the Bristol Bay or Bethel
areas) •
The future village reconnaissance studies to be conducted for
the Authority could be structured to be followed by an overview
which compares the results of individual studies to identify the
potential for a regional or sub-regional approach, or to rank the
villages for more detailed analyses based on the results of the
reconnaissance level studies. Although the Authority's procedures
do not reflect this specific approach, the Bristol Bay and Bethel
studies indicate that the Authority is moving in this direction.
It may be appropriate to formally recognize this approach in the
Authority's procedures.
This second phase of the reconnaissance study would use one or
more load growth scenarios, based on alternative forecasts, alter-
native interconection concepts, or a combination of both to eval-
uate power supply alternatives. However, an administrative ~roblem
can arise with this phased approach. Unless the Authority conducts
the preliminary analysis itself, the budget for the total recon-
naissance level study is not accurately known until the first
phase, as described above, is completed and the scope of the
remainder of the study is known. This could be overcome by budget-
ing slightly more for the studies than is currently done and
withholding a reserve for augmenting budgets.
In several of the reconnaissance level studies, renewable
~esour<;:e projects are identified as technically feasible,~ bu.t ,
economically infeasible due to insufficient energy demand in the
projections utilized. Since bush-village energy demands can
increase substantially with the addition of a commercial facility
in the area, it may be appropriate in some cases to conduct prelim-
inary sensitivity analyses to identify the energy demand level that
might be needed to make such alternatives economically superior. A
review of the results of reconnaissance level studies would then be
3-31
made periodically to determine whether an update is warranted. The
results of the sensitivity studies could be used to rank the vil-
lages in terms of priority for future re-evaluation. For example,
a village where energy demand must triple before alternatives to
diesel generation_ become economically superior would have a lower
priority for re-analysis than a village in which a fifty .Percent
increase would make alternatives potentially economically superior.
This type of analysis would also help eliminate some of the criti-
cism by local citizens that demand projections used to evaluate
alternatives are not as optimistically high as they would hope for.
If energy demands increase at rates which would justify considering
alternatives preferred by the local community, the Authority could
then consider such options.
Still another alternative is to augment the present value life
cycle cost evaluation method with other economic evaluation
criteria, including nominal cost of power analysis,~ using shorter
periods for the present value life cycle analysis, and using
savings to capital investment ratios.ll/ Although nominal cost of
power analyses are now being included in Authority studies, it is
not clear how the results of these analyses are factored into the
decision making process. This is discussed in more detail below,
with respect to detailed feasibility studies.
Feasibility Assessment
This section addresses the process of using the results of
reconnaissance level studies to select projects for detailed
feasibility analysis. Since the analysis of the feasibility of
individual projects leads to selection among alternatives for
project development (where alternatives have been identified),
this ranking and selection is an important part of the power
planning process.
3-32
Selection of Projects for Feasibility Assessment
and Ranking of Alternatives
Prior to reviewing the current practices in feasibility
assessment, it is important to note that many of the completed
feasibiiity studies which have been used by the Authority have
either been "inherited" from other organizations or are studies
which were conducted for the Authority based on the results of
reconnaissance level studies which were conducted by other organi-
zations.l]/ Therefore, some of the problems identified are
associated with parties who are no longer directly responsible for
the continued power supply planning process in Alaska.
Furthermore, studies such as those for Bristol Bay and the Bethel
~ j
area have shown a significant improvement in scope and approach as
compared to past studies.
Current Practice in Selecting Projects for Feasibility
Assessment
The Railbelt Alternatives Study is the closest effort to a
reconnaissance level study which has been conducted for the Rail-
belt area. In terms of scope and depth of analysis, the study was
much more extensive than a regional initial reconnaissance study.
However, due to the timing of its completion, several detailed
feasibility studies for specific projects in the Railbelt were
completed before the Railbelt Alternative Study was completed, or
even started. Because of this there was not a framework for eval-
uating the results of the project-specific feasibility studies
which had been completed in a manner which allowed comparison of
the study results when they were conducted. The Railbelt Alterna-
tive Study may now form the basis for detailed evaluation of
' '
specific projects and groups of projects. However, the level of
detailed analysis of new projects relative to the susitna project
is likely to remain a problem for a comparative evaluation.
The use of reconnaissance studies in the bush and Southeast
Alaska has varied depending primarily upon how long ago the
reconnaissance level studies were conducted. Projects which are
in advanced stages of development (Lake Tyee, Terror Lake and
3-33
Swan Lake, for example) had feasibility studies which were either
conducted by other agencies or were based on reconnaissance level
studies which were conducted to identify alternatives to those
projects after the projects had already been identified as
"prefer red." This is similar to the approach which has been used
for Susitna, discussed above.
· The Authority is currently selecting feasibility studies based
on more extensive and consistent reconnaissance level studies in
bush locations. The general approach taken in the past appeared to
be to select a single preferred project with the lowest present
value life cycle cost as identified in the reconnaissance level,
where a clear economic preference was indicated in a study. How-
ever, in many of the studies, the present value life cycle cost
evaluation method has not identified substantial economic dif-
ferences between the alternatives evaluated at the reconnaissance
level. The Authority has, therefore, recently moved towards a two-
stage feasibility assessment following the conduct of the recon-
naissance level studies. The Bristol Bay, Bethel area, Kotzebue,
and Cordova studies are examples of this approach.
Strengths of the Current Process for Selection of Projects
for Feasibility Analysis
The strengths of the current process for selecting feasi-
bility studies from reconnaissance results are the attempt to
make such reconnaissance studies-consistent, to the extent
possible, and-to conduct them concurrently to. allow for com-
parison of results. The recent efforts to standardize the
reconnaissance study approach should improve the ability of
the Authority to set priorities for authorizing feasibility
studies of promising projects in. t.he. bush co.mmunities.
The "two stage" feasibility assessment to consider alter-
natives identified in reconnaissance studies before determining
which projects are to be considered preferred alternatives for
detailed feasibility analysis is a major improvement in the
planning process.
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Weaknesses of Past and Current Process for Selection of
Projects for Feasibility Analysis
From the description of the process used to select pro-
jects for feasibility assessment in the past, several weak-
nesses can be identified:
0
0
The lack of a reconnaissance level review of Railbelt
alternatives until recently has resulted in piecemeal
evaluation of the alternatives. The feasibility studies
which have been conducted for each alternative are
therefore not likely to be as useful for selecting alter-
natives for development as they would be had the.studies
been conducted following area-wide reconnaissance studies
before the extensive studies of Susitna .were performed.
The reliance on the lowest present value life cycle
cost for project evaluation in the reconnaissance level
studies leads to a bias towards selecting only one pro-
ject for detailed feasibility assessment when one project
is identified as being capable of meeting the study area
demand. This precludes the comparison of what could b~
economically preferable projects which were ranked clo~e
to the "preferred alternativen at the reconnaissance
level. If any of the major assumptions change, project
ranking can shift dramatically. Using a single criteria
heightens the risk of selecting an inferior project. The
0 two stagen feasibil~ty study process the Authority is
moving towards may alleviate the problems of inadequate
data availability at the reconnaissance level stage.
This should provide for a more extensive analysis of
alternatives before planning work focuses on one
preferred alternative.
Alternative Approaches to Selecting Projects
for Feasibility Assessment
Alternative approaches to selecting projects for feasibility
analysis include the following:
o .. · ..... "Where--· more· than· one alternative .. evaluated in the >
reconnaissance study appears potentially feasible, more
than one project can be evaluated in the detailed
feasibility study to provide a more complete basis for
the selection of a project for development. It appears
that the Authority evaluation process is moving in this
direction. If so, the formal procedures should be
updated to reflect this change.
3-35
0
o_
If a reconnaissance study has been completed, but
questions regarding alternative interconnection or load
growth scenarios remain, an augmentation of the
reconnaissance study to identify other potential
alternative projects for detailed analysis can be
undertaken before detailed feasibility studies begin,
either separately or as an initial phase of the
feasibility study.
Economic evaluation methods, in addition to, or in lieu
of present value life cycle cost, could be used to
evaluate projects at the reconnaissance level stage
. (see discussion in the following section).
Economic Evaluation Procedures in
Feasibility Assessments
The objective of the Authority's detailed feasibility
assessment is to compare one or more alternative power supply
projects (or power supply plans) to a base case plan to form the
basis for a final recommendation for development of one or more
projects. The present value life cycle cost analysis is the ana-
lytical method and decision making criteria used by the Authority
in these assessments. The following describes the strengths and
weaknesses of this methodology and offers some alternatives for
consideration to augment this evaluation concept.
Current Economic Evaluation Practice
After a specific project has been selected for detailed feasi-
bility assessment, the Authority utilizes a standard procedure
which it has adopted to perform project evaluation. This evalua-
tion procedure is aimed at providing consistency between feasi-
bility studies. The approach used is basically a more detailed
version of the reconnais.sanGe le,vel evaluation,
fewer number of projects and in greater detail.
projects evaluated in the detailed feasibility
only focused on a
The project or
study are compared
to a base case which is generally a thermal power plant or system.
The current dollar "overnight" capital and operation and main-
tenance costs of the base case plan and alternatives are estimated
in a traditional manner.~ The Authority then uses an "inflation
3-36
freen method to estimate installed capital costs and future annual
project costs in today's dollars with an assumed real escalation
rate for capital costs, fuel costs, and operation and maintenance
costs. These annual costs are estimated over a period equal to the
longest economic life of the projects under consideration with no
escalation of costs after twenty years. As an example, if a study
uses a plan with a hydroelectric project with a fifty year life
planned for construction ten years into the planning period, the
Authority would use a sixty year evaluation period to estimate
present value life cycle costs. Where the present value life c.ycle
cost of an alternative project or plan is significantly lower than
the· other alternatives, this lowest present value cost alternative
is usually recommended for development.
The Authority has found that in comparing capital intensive
projects such as hydroelectric projects with diesel generators or
other thermal alternatives, the high initial energy costs asso-
ciated with the hydroelectric projects result in financing complex-
ities due to the high initial energy costs. Recently, considera-
tion has been given to the impact on project economics of delaying
the development of hydroelectric projects as a variable in feasi-
bility studies. The purpose of this approach is to determine
whether delaying implementation'of a project will yield a lower
present value cost for the project, as compared to the base case
alternatives. This ntimingn analysis has been of particular
interest to the Authority in situations where the difference in
present value costs between alternatives is not large.
Strengths of Current Economic Eyalation Procedure
in FeasibiityStudies
The main strengths.of the current feasibility
assessment economic .. evaluation methods are:
0
0
The effort to use a consistent methodology and economic
criteria. This is particularly important when the State
must assist in the financing of several projects of
various sizes, project lives, schedules for implementa-
tion and geographic location.
The recent efforts to consider different implementation
schedules for projects when evaluating project feasi-
bility.
3-37
Weaknesses of the Current Practice
The weaknesses of the current economic evaluation
methods used in the Authority's feasibility study procedure
pertain to the reliance of a present value cost method on
long term assumptions regarding real fuel cost escalation
and forecasted demand. While the Authority appears to
utilize alternative economic assumptions in its present
value cost analyses, it is not clear how these alternative
assumptions are utilizd in the decision making process. The
following identifies some of the weaknesses of the past
practices of utilizing the results of the present value
life cycle cost analysis method:
0
0
The Authority has regularly included a range of real fuel
cost escalation rates as a sensitivity analysis in feasi-
bility assessments. Most final feasibility studies per-
formed for the Authority include zero real fuel esca-
lation in addition to average rates of approximately 2 to
3 percent annual real escalation. The Authority also
adopts a "most likely" average fuel cost escalation which
is constant over a twenty year period of analysis.
Although analyses are conducted using lower fuel escala-
tion rates, and these results are presented in final
feasibility studies and the Authority's Statements of ·
Findings and Recommendations, it appears that the final .
recommendations have previously been based on the adopted
"most likely" fuel cost escalation scenario. In FY 1982,
the Authority adopted an average annual real fuel cost
escalation scenario of 2.6 percent/year for 20 year
studies. The result of using this high of a real escala-
tion rate when expressed in nominal dollar terms (esti-
mated future costs including estimates for the general
rate of inflation) is shown in the Tyee Lake sample
evaluation in Appendix 3-A (see Exhibit 3-2 in the Appen-
dix). If lower rates of fuel cost escalation are being
used in the decision making process, the presentation
of the findings~and recommendations· have not clearly
indicated how the results of analysis using the lower
escalation rates were considered.
The use of present value life cycle cost as the sole
economic criteria for determining project feasibility
de-emphasizes the near to intermediate term energy cost
increases associated with capital intensive hydroelectric
projects, as compared to the thermal base case. The use
of a 50-year evaluation period for present value analysis
for hydroelectric projects can create a very misleading
perspective of the attractiveness of a project. The
3-38
0
Authority has incorporated nominal cost of power esti-
mates in their studies, but it is unclear how this
analysis .is utilized in the decision making process. As
an example, the diesel generation nominal power cost
curve shown in Exhibit 3-2 in Appendix 3-A would tend to
suggest that there would be some response to energy
demand on behalf of the consumer, or fuel supply substi-
tution which could impact such long term escalation
before the nominal fuel cost values in the later years of·
the forecast were incurred. It is not clear .that the
effective nominal power costs are considered in estab-
lishing the real escalation rate which is used as the
basis for the present value life cycle cost analysis.
More emphasis on the near to intermediate term power
.costs appears warranted. Appendix 3-A addresses this
problem with a quantitative example comparing alternative
methods of evaluating project economics.
The public can be misled by power cost estimates
expressed in constant dollars. The State is proposing
to subsidize project costs and the total magnitude of
such a subsidization program can be misunderstood when
base year, inflation-free cost estimates are used for
estimating project feasibility. Nominal dollar estimates
would provide an additional perspective of the size and
timing of State expenditures. The Authority is providing
this information in more recent studies, which should
help focus more attention on the power marketability
issue.
Alternative Approaches to Feasibility Assessment
As alternatives to the current procedure for feasibility
assessment, the following strategies for structuring feasibility
assessment could be utilized to better meet power supply planning
requirements:
0 The selection of.the fuel cost escalation rate, in most
cases, is the most significant decision that the
Authority ~ust make in conducting a present value life
cycle cost analysis. Since the present value cost of
oil or gas fired generation is so sensitive to fuel
cost escalation, the Authority may want to consider
inqorporating an ... explicit .. analysis. of alternative fuel
cost escalation rates on a project-specific ·basis which
considers the cost of power including an estimate of
general inflation. The efforts of the Authority to
eliminate the vagaries of the general rate of
inflation in their future cost analyses is
understandable. However, when the "most likely"
scenarios used in past studies for the Authority are
reviewed in nominal power cost terms for a specific
project, lower rates of real escalation could be seen
as being likely as well. Although additional economic
3-39!
0
0
0
evaluation scenarios can be viewed as "information over-
load", once the feasibility study has narrowed down the
reasonable alternative scenarios to a manageable number
some additional fuel cost escalation sensitivity analysis
could be performed. In cases where controversy regarding
the recommendation to develop a project has been encoun-
tered, the Authority has conducted sensitivity analyses.
One approach to this sensitivity analysis, 'once a tenta--
tive "preferred" project or plan has been identified, is
to determine the real fuel escalation which corresponds
with a 1.0 benefit cost ratio. The decision-making can
then focus on the perceived risk that fuel cost escala-
tion will be less than that "break-even" rate over the
period of analysis.
In addition to the use of a 50-year project life for a
present value life cycle cost, a shorter term analysis,
for example 20 years, could be used to evaluate the
near and intermediate term cost of the project
alternatives. such analysis could also be under~aken
using nominal dollar costs, including estimated
inflation rates, to present the best estimate of the
costs of the alternatives. This could be estimated in
addition to the "inflation free estimate." Appendix 3-A
provides a comparison of the 50-year present value
cost method to a 20-year analysis. The purpose of the
20-year analysis is to determine ~ the benefit from a
project which has a lower fifty year present value life
cycle cost is expected to occur. This approach takes a
nsnapshot" view of twenty years of operation, disregard-
ing the salvage value of the equipment at the end of that
period. (This method also disregards the remaining debt
service payments due in the case of a hydroelectric
project financed with long term debt, on the basis that
th~ project would continue operating at a "profit" after
twenty years, in any event). This analysis provides an
indication as to how dependent a "preferred" project
(using a 50-year analysis) is upon the cost savings which
occur after the 20-year planning period in order to
obtain the estimated total value of the 50-year present
value cost savings.
The calculation of the present value savings per dollar
of capital investment anticipated to be obtained from a
project over a period of time, such as during its
commercial life, provides a measure to assess the
relative cost-effectiveness of alternative projects.
Appendix 3-A provides a sample calculation of the savings
per incremental dollar of capital expenditure for the
Tyee hydroelectric project as compared to continued use
of diesel generation to provide an indication of the
application of this evaluation method.
Another method of evaluating near-term project
economics is to incorporate the cumulative present
value break even cost of the alternatives in the
analysis. By including this evaluation, the decision
3-40
..
maker would know how many years it would take (on a
present value basis) for, as an example, a
hydroelectric project to recover the higher cost of
power in the early years of operation due to the
savings anticipated after thermal power costs exceed
the hydroelectric project power costs.
Selection. peyelopment. and Authorization
After feasibility studies are complete, the project or
projects found to be feasible and desirable for development must
proceed through the authorization process. This section
addresses the phase of the power supply planning process which
combines the review of feasibility study results with considera-
tion of project financing alternative~ to make a decision on
project authorization.
Current Practice of Project Selection
The authorization process for power development in Alaska
involves a multi-tiered review process. It originates with a
staff recommendation to the Authority's Board of Directors and
culminates with the enactment of law authorizing the power
project ana· approving its construction cost. The ultimate
decision-making authority for most major projects resides with
the State Legislature and its decision is based on
recommendations from the Division of Budget and Management in the
Office of the Governor and from the Authority's Board of
Directors. To review the authorization process it is appropriate
to first review the steps which proposed projects must complete
before the Board recommends them for budget authorization.
Although reconnaissance and feasibility studies must pass through
authorization processes of their ~wn, the focus of this next
section is on the process used to authorize projects to proceed
beyond the feasibility stage.
Feasibility Study and Finance Plan
A reconnaissance study for a proposed power project is
considered approved if it has not been disapproved by the
3-41
Division of Budget and Management within 30 days of submis-
sion. Once approved, the Authority must complete a feasi-
bility study and plan of finance for each proposed project if
they want to proceed to the next phase of the authorization
process.
A-feasibility study is used "to assess the technical,
economic, and environmental aspects of a power project or
program identified in a reconnaissance study so that the
Authority may decide whether to apply for licenses or permits,
or invest in detailed engineering and design."2Q/ A feasi-
bility study must include detailed information concerning the
proposed project, a statement of all assumptions which affect
the feasibility of the project, a comparative analysis of all
{easonable alternatives to construction of the project, and
information based on engineering and design work which meets
the requirements for submission to the Federal Energy Regula-
tory Commission of a license application.
The purpose of the plan of finance is "to present various
alternatives available to finance the power project and to
identify the most appropriate mean~ to achieve the lowest cost
electric power for consumers while minimizing the amount of
State assistance required."ll/ It must include recommenda-
tions of the most appropriate means to finance a project.
These means·include, but are not limited to, the following:
revenue bonds, general obligation bonds, revenue bonds of the
Authority with partial or full guarantee of the. State, an
appropriation or loan from the General Fund, financing
arrangements with other entities using leveraged leases or
other financing methods, assistance from any federal agency, a
loan from the Power Project Fund or the Renewable Resources
Investment Fund, or any combination of the financing arrange-
ments listed above.
When any State assistance is necessary for a project to
meet financial feasibility criteria, an estimate of th~ mini-
mum amount of financial assistance required by the project
from the State must be included in the plan of finance. This
assistance must be stated in terms of estimated present value.
3-42
The techniques applied in determining the information
required, and the standard criteria and measures for compara-
tive analysis of alternative financing arrangements are
adopted in regulations which are developed jointly by the
Authority and the Division of Budget and Management. As a
result, plans of finance and feasibility studies should be
relatively consistent between projects, at least in format,
and readily understood by all parties.
Review by Division of Budget and Management
When these two documents are completed, they are
forwarded to the Division of Budget and Management (DBM) in
the Office of the Governor for review for compliance with the
provisions noted above (condensed from AS 44.83.181 (b)-(d)).
The DBM can obtain an independent evaluation from another
source of the feasibility study and plan of finance at this
stage if they feel it is warranted to comply with the provi-
sions mentioned previo~sly.
. I
When the DBM has completed it~ review of both reports,
it submits a report to the G6vernor which includes a finan-
cial analysis that evaluates the project's proposed bond
resolutions or other financial plans or arrangements, and
their impact on the total direct and indirect indebtedness of
the State. The report includes a recommendation to the
Governor and Legislature for approval or disapproval of the
proposed project, again based on compliance. with the require-
ments of AS 44.83.181 (b)-(d). This report must be completed
and submitted not later than 60 days after having been
received by the DBM.
Authority Process for Recommendation of Projects
Upon completion of a draft feasibility study and plan of
finance for a project, the Authority distributes both for a
period of 60 days for review by staff, other agencies, and
the public. The Authority Board of Directors secures an
independent cost estimate for the project from its consulting
3-43
engineer. The findings of the consulting engineer and the
staff, combined with any agency or public input are presented
in a briefing to the Board and are addressed one by one in
the final feasibility report. This briefing includes a
review of project costs, technical feasibility, environmental
impacts, financing options, and public.and agency prefer-
ences. From this review the Board decides whether to seek
required permits and licenses and initiate design (subject to
legislative authorization of the project). The Board has the
authority to approve all permit acquisitions, initiate pro-
ject design and award design contracts, once legislative
authorization and appropriation of funds have been obtained.
The Executive Director prepares a "Statement of Findings
and Recommendations" and submits it, along with the feasi-
bility report and finance plan to the Governor, the Legisla-
ture, and the DBM. The DBM reviews the feasibility report and
plan of finance and transmits independent recommendations to
the Legislature and the Governor.
It is important to note that under the present written
procedures, the Authority's decision to recommend a project
for licensing and design can be considered as a recommendation
to prepare for construction assuming that upon completion of
licensing and design the project remains technically, economi-
cally, and environmentally feasible. Thus, approval by the
Legislature for design and licensing could be an authorization
to develop the project, with certain final review requirements
as described in the next section. The Authority has, however,
considered legislative authorization as approval to conduct
project design only. The Legislature's decision on appropria-
tion of funds for construction after design is complete is
considered by the Authority to be the final authorizati~n to
construct a project.
Submission to the Legislature
The Legislature, for any proposed power project, will
have in its possession at this stage reports and documents
from the Alaska Power Authority and the Division of Budget and
3-44
Management in the Office of the Governor. The Legislature's
materials and their sources are:
0
0
Alaska Power ~uthority
Statement of Findings and Recommendations
Feasibility Studies
Plans of Finance
Division of Budget and Management
Recommendations concerning the project
Analysis of Authority Feasibility Studies
Analysis of Authority Plans of Finance
In fact, all three players in the process, the Governor,
the Legislature, and the DBM receive these six reports which
analyze the proposed project from different perspectives. The~
different viewpoints should provide sufficient data to make an
informed decision. The problem lies in sorting through the
information and determining the most appropriate analysis upon
which to base a decision.
The project authorization process is treated as a compo-
nent of the total annual State budget review and authoriza-
tion. To receive authorization for projects, the Authority
compiles the results of feasibility studies which have been
completed in sufficient time to be considered in the annual
State budget process.
To present its recommended projects to the Legislature,
the Authority separates the State into three geographic plan-
ning regions -the Railbelt, the Bush, and Southeast Alaska.
Jror. ~ach region, the regional power. S'!!PPlY issues are-
described and the recommended power development program
efforts from reconnaissance study through construction author-
ization are briefly presented. In support of recommendations
for project licensing, design,and construction, the Authority
presents a brief background on the alternatives considered,
and the results of the feasibility analysis on the basis of
the present value life cycle cost estimate.
3-45
The Legislature reviews the projects presented by the
Authority and considers the individual projects and the total
request. The fact that the authorization decision is made by
the Legislature is a significant factor in comparing Alaska's
power supply planning process to the process typically used
for a utility service area. In addition to consideration of
the merits of individual projects, the power development pro-
gram budget must be considered in light of other State budget
priorities.
The Legislature considers and must approve all proposed
new projects except those that are exempt under AS
44.83.187.2.2./ The Authority may proceed with the engineering
and design work necessary to meet the requirements for submis-
sion to FERC of a lice~se application, but may proceed no
further toward project completion until the Legislature
approves the proposed new project. Approval of a proposed new
project comes only by the Legislature enacting a law that
authorizes the project and approves its construction costo
Recently there was a proposal to adopt a method to expe-
dite the process from project design to construction. The
procedure provided for the Authority to obtain a final cost
estimate from a source independent of the firm which conducted
the project design and is qualified to make such an estimate.
The objective of this independent review would be to determine
whether the expected project costs exceed the authorized
budget by more than 7.5 percent, adjusted for inflation. If
the costs are within this margin, the Board would be provided
with an update of project feasibility and a recommended plan
of finance.
Under this plan, if the final cost estimate exceeds the
aqthorized budget; adjusted for inflation, by more than 7.5
percent, the feasibility report would be revised to determine
if the project is still feasible. If the Board feels that the
project is feasible, it would submit the revised feasibility
study and the independent cost estimate to the Legislature for
reauthorization. Any project which is returned for recon-
sideration would not be constructed unless the Legislature
reauthorizes it by enacting law for that purpose.
3-46
The Authority has not adopted this procedure and has
recommended that it not be adopted. The Authority has not
operated under the assumption that authorization for design
infers approval to construct a project. Therefore, the
Authority makes recommendations to the Legislature for appro-
priations for construction on each project to be developed.
If, based on the review of final design cost estimates, the
project feasibility is questionable, the Authority would
recommend an updated feasibility analysis prior to requesting
authorization for construction from the Legislature. Even
after Legislative authorization and appropriation of funds
from the Legislature, the Board often awaits receipt of major
construction contract bids before giving final approval for
the project. Final approval often takes the form of an ini-
tial construction contract award. The Board has the authority
to approve by resolution any indebtedness for an authorized
project for which an appropriation has been approved by the
Legislature.
Weaknesses of the Current Practice in Project Authorization
Many of the difficulties currently experienced in the
project authorization process are attributable to the very nature
of a legislative approval process. For instance, due to the .
unconventional body which performs power supply decisions,
Alaska's power supply planning process has experienced
difficulties such as: State funding uncertainties which lead to
financing plan uncertainties, and untimely yearly budget review
periods relative to project study completion dates which can
preclude project development until the next annual budget review
occurs. Limitations to-the amount of•time·that the Legislature
can devote to power supply plannii1gissues, and the transitory
nature of the tenu~e of elected positions are also inherent
weaknesses in the decision making for Alaska's power supply
planning. The evolving nature of State policy on financial
assistance for power development has also hampered the
authorization process.
3-47
At present, the State is in the process of developing a plan
for determining how to utilize State funding to assist in project
financing. Therefore, the Legislature must currently consider
the authorization of power projects based on tenuous State
funding, with a final financing plan to be confirmed at a later
date. The financing pl~n which is finally adopted can substan-
tially impact the present value life cycle cost for the proposed
alternative relative to the base case thermal plan or other
alternatives. This uncertainty has complicated decisions by the
Authority to recommend projects for authorization and for legis-
lative action.
One problem with the current practice is that the State
Legislature reviews only those projects for which studies have been
approved. Often there are time frame differences which preclude
some projects from consideration in the State's yearly budget
authorization. Important projects which stand alone or complement
an energy grid can be closed out from the annual authorization
"window" because of technical delays or minor deficiencies which
delay agency approval at lower levels of the process. In these
instances, invaluable supplementary information which would enhance
decision making at the authorization phase can be precluded from
consideration. This contributes to the project-by-project approach
to power supply planning in Alaska, especially if only those pro-
jects which are included in that fiscal year's budget proposal are
considered.
Another weakness inherent in the current procedure is that
previous efforts and experiences in the planning activities are
not given sufficient exposure to today's decision making bodies.
This reduces the extent to which the decision makers can learn
from others' past efforts. For instance, the presentation of the
process used to recommend the proposed projects,, including the
alternatives considered and discussed, is an important input to
the decision making process. With the project-by-project
approach which is inherent in a legislative budget review, the
role that an individual project has in the study area is not
easily understood. Where a proposed project meets a portion of
the needs of the study area it is difficult for a decision to be
made on that project absent some analysis of other alternatives
3-48
currently under evaluation to augment the project. This places a
burden on the Authority to document past planni~g assumptions and
decisions in an attempt to maintain a consistent planning process.
All this seems to suggest a more comprehensive presentation
process at higher levels of the authorization process. More
complete, and painstakingly detailed proposals would surely
improve the amount of information on alternatives and their
respective feasibilities within a regional power development
scheme. But this solution would not be without its costs. There
is the potential for information overload on parties whose
time is definitely finite. In a normal utility setting these
decisions are made by full-time managers, specialized in their
field. For legislators who make the final decision, these issues
are but one of many issues they face in a hectic schedule. Their
lack of experience in power development, together with rapid turn-
over (as compared to a career utility manager) makes the approval
of projects that much more difficult for them than for their
counterparts in the utility industry. Although they have profes-
sional staffs and support facilities, none-the-less, these
weaknesses are inherent in the system.
Another factor which creates difficulties for the process is
that it is very difficult for the Legislature to reach a concen-
sus on development priorities for proposed projects. Often there
is a natural tencency for legislators to want projects in their
districts to receive priority. Likewise, their colleagues may be
hesitant to agree to particular bills for fear that funds will be
unavailable later for projects in their districts. Of course,
this is not the rule, but it is a factor which has hindered
statewide development priorities.
Alternative Approachesnto Project Authorization
Because the Authority is a State agency and the State of
Alaska has made a significant financial commitment, through the
budget process, for power project development, the project appro-
val process is somewhat different than for projects in other
areas of the country. In effect, there is not a single decision
to proceed with the project that is required, but rather that
3-49
decision and then annually a formal decision appropriating funds
for construction. This is complicated by restrictions on the
commitment by one legislature of a future legislature.
An alternative that might be considered, in this regard, would
be to bifurcate the approval process generally as follows:
0
0
At the point in time that a project is identified,
studies have been completed, and a decision has been
made at the staff level to seek Authority Board of
Directors and legislative approval, documentation
should be developed which is focused on the decision
makers involved. This documentation would be supported
by the bulk of studies underlying the staff's decision,
but would serve as a summary that periodically would be
updated for the use of those who must finally approve
the project.
This documentation would be submitted with other authori-
zation documents as a packag~. An important element of
this document would be a cash flow forecast both in con-
stant and current dollars for the proposed project. This
cash flow forecast, segregated by source of funds (bond
proceeds or legislative appropriations), would reflect the
estimate of the annual appropriations that would be
required.
Under such an approach, the first decision required would be
whether or not to proceed with the project. Following this, the
Legislature would have to address the question of appropriations
annually. The· "decision documents" should be periodically updated,
not only at the time that annual appropriations are required, but,
equally as important, when certain milestones were reached. These
would be identified in the request for approval of the project •
These milestones would include completion of· engineering design with
engineered cost estimates, receipt of bids for construction, and
other events that trigger decisions.
3-50
APPENDIX 3-A
CASE ANALYSIS
TYEE LAKE HYDROELECTRIC PROJECT
Introduction
As discussed in Section 3, the 50-year present value cost
evaluation method (present value analysis) is used by the Authority
to evaluate the feasibility of hydroelectric projects. This method
of evaluation provides one perspective of project feasibility.
This appendix provides a sample evaluation of the Tyee Lake Project
(Tyee) to compare a 50-year present value analysis with a similar
analysis considering only the first 20 years of operation and a
cost estimate in nominal dollars for both Tyee and the base case.
In addition, as a method to evaluate the economic return on the
capital investment in the project, the present value of the antici-
pated savings from the project, as compared to the base case, is
estimated on .the basis of savings per incremental dollar of capital
investment.
This example shows the advantage in using more than one
method of evaluation to assess feasibility. The alternative
methods described in the examples provide a means for determining
whether the long-term cost savings indicated in a 50-year present
value analysis appear sufficiently attractive to warrant State
funding.
Some simplifying assumptions were used to conduct this
analysis, therefore, the absolute value of project energy costs
and present value costs should not be considered as estimates for
comparison with the results of previous studies. No effort has
been made in this example to conduct analyses using different
escalation rates or to perform any sensitivity analyses, as might
be conducted in a complete analysis. The purpose of this sample
analysis is to illustrate the potential value of augmenting the
3-51
50-year present value life cycle cost method of economic evaluation
with other criteria.
Background.
An analysis of the Tyee Project was completed for t~e
Authority in December of 1981. The purpose of the Tyee Lake
Hydroelectric Project Findings and Recommendations (Tyee Report)
was to provide justification for an appropriation of funds for
construction of the project. In keeping with the Authority's
standard economic evaluation procedure, the report compares the
present value cost of energy from Tyee to the alternative cost of
energy from diesel generation over the same period. Diesel and
existing hydroelectric generation currently serve the communities
of Wrangell and Petersburg, and it was assumed that the diesel
generation would be displaced by Tyee. The analysis presented
here is based on the assumptions of the Tyee Report. The assump-
tions and methods used to estimate the comparative costs of Tyee
with the base case are described in Attachment 1.
Comparison of Alternative
Economic Evaluation Methods
Nominal Dollar Cost of Energy
The cost of energy per kwh for Tyee and the base case in
nominal dollars is shown in Exhibit 3-2. The results of com-
paring Tyee with continued use of diesel generators with waste
heat recovery is shown in Exhibit 3-3.
Using the criteria of the present value analysis over the
expected 50-year economic life of Tyee, the project appears· sig-
nificantly superior to the base case, with a present value cost of
approximately $160 million compared to approximately $330 million
for diesel generation, based on the assumptions used in the Tyee
Report. However, viewing the unit energy cost in the near and
intermediate term, as shown on Exhibit 3-2, indicates the dependence
of this long-term cost savings on the continued high escalation of
diesel fuel costs. As shown, on a present value basis, the losses
3-52
EXHIBIT 3-3
SAMPLE ECONOMIC COMPARISON OF
TYEE LAKE HYDROELECTRIC PROJECT
AND DIESEL GENERATION
Adjusted 11 Tyee Lake Project Cost 11 Diesel Generation Costs 11
Energy Sales Total Cost Unit Cost Total Cost Unit Cost
Year (MWH) ($xl000) (¢/kWh) ($xl000) (¢/kWh)
1984 27,616 12,961 46.9 3,914 14.2
1985 30,372 13,091 43.1 4,617 15.2
1990 46,471 13,890 29.9 11,280 24.3
1995 60,091 15,010 25.0 23,647 39.4
2000 75,636 16,581 21.9 44,595 59.0
2005 90,921 18,282 20.1 72,301 79.5
2015 90,921 18,282 20.1 72,782 80.0
2025 90,921 7,175 7.9 72,348 79.6
2033 90,921 7,175 7.9 72,348 79.6
Present Value of Cost over 20 years:
Diesel Generation
Tyee Lake
$132,583,000
$120,812,000
Present Value of Cost over 50 years:
11
y
ll
Diesel GeneLation
Tyee Lake
$330,293,000
$158,841,000
This is the projected annual demand for energy to be purchased
from the project. The project produces more energy than is
projected to be required in the area for. several years of
operation. No growth of ·energy demand is assumed after 20
years of operation.
Although Tyee operating costs escalate with inflation, load growth
increases are adequate to cause unit energy costs to decline
continuously. A large drop in cost occurs after 2018 when debt
service is paid off.
Cost of diesel generation increases steadily until 2003,
which inflation and real escalation are assumed to be 0.
total cost fluctuates slightly after 2003 as capacity is
and replaced at slightly different costs.
3-54
after
The
retired
in the early years of project operation under these assumptions
would be recovered from long-run project savings in approximately
the year 2001, 17 years after project has commenced commercial
operation (based on the assumptions used in the Tyee Report).
Average annual energy costs from Tyee are estimated to be equal to
diesel energy costs in approximately 1992.
Shorter Term Evaluation of Present Value Costs
A major criticism of 50-year present value analysis is the
uncertainty of long-term costs and lack of knowledge of the future
availability of other lower cost technologies not currently
commercially available. Another method for evaluation would be to
compare the first 20 years of operation of Lake Tyee to.the base
case. Project capital costs are still amortized over 35 years in
this example. The analysis merely takes a 20 year "snap-shot" of
project costs to compare the present value costs with the base
case for the first 20 years of operation. Twenty years is used as
a period over which greater forecasting accuracy is achievable
compared to the virtual uncertainty of forecasting between 20 to
50 years in the future (The Authority has recognized the long term
uncertainty in their analyses by stopping all cost and price
escalation for values after 20 years. This analysis ignores both
the salvage value of the equipment and remaining debt service
payments after 20 years on the presumption that the hydroelectric
project would remain operating after 20 years as an economic
alternative to thermal generation).
As shown in Exhibit 3-3, the 20 year present value cost of Tyee
is marginally less than the diesel base case. Thus the large economic
advantage of the Tyee project indicated in the 50 year analysis is
achieved after the first 20 years of operation. . ' . .. . ~ . ~· ' ,_
This type of information would be helpful in determining
whether a project appears sufficiently attractive in the long-term
to warrant State subsidizing or restructuring debt service pay-
ments to make near term power costs competitive. The presentation
of energy costs in nominal dollars also helps identify the likely
amount of the subsidy that would be required.
3-55
Savings to Investment Ratio
Although a review of annual power costs over the project
life and shorter term evaluation of present value project costs
provide an additional perspective on project economics, neither
method of viewing costs is well suited as a basis for comparing
the relative attractiveness of different projects. One method of
evaluating several projects, either within a region or statewide,
is to compare the projected savings of the alternatives over a
base case cost on the basis of savings per incremental dollar of
capital investment. Power projects of different size, location
and service area can be evaluated, compared, and a prioritization
established based on the expected return in savings per dollar of
capital investment.
This concept is not necessarily one which is commonly used by
electric utilities. The marketability of power from a project
relative to available alternatives, and the nmeldedn system cost of
power by the addition of a new resource are more conventional
methods to determine project feasibility in a typical eleactric
utility system. However, with the broad range of existing power
costs, and the limitations on available alternatives in many
regions and communities, the savings per dollar of capital
investment is an evaluation method dese~ving of consideration by
the Authority • .W
As an example of this approach to evaluation, the estimated
savings per dollar of capital investment was calculated for Tyee
for the first 20 years of operation and for 50 years of operation
as compared to continued diesel generation. Exhibit 3-4 presents
this calculation for the 20 and SO-year present value savings.
To conduct this analysis, the present value capital cost of Tyee
is compared to the present value capital cost of the additional
diesel generating capacity which would otherwise be added over
the period of analysis. To evaluate the savings per incremental
dollar of capital investment for Tyee, the difference between the
present value capital costs is divided by the present value
savings expected from Tyee.
3-56
SAMPLE CALCULATION OF
SAVINGS TO INVESTMENT RATIO
TYEE. LAKE HYDROELECTRIC PROJECT
EXHIBIT 3-4
20 Year Savings To Investment Ratio 11
Present Value Cost Over 20 Years
Diesel Generation
Tyee Lake
Savings
Present Value Capital Costs
$132,583,000 y
120,812,000
11,771,000
Tyee Lake $103,700,000 ~
Diesel Generation 20,464,000 •
Incremental Present Value
Cost of Tyee compared to Diesel Generation $83,236,000
Savings/Incremental Capital Investment =
11,771,000/83,236,000 = 0.141 = $0.141 savings per dollar of capital investment
SO Year Savings To Investment Ratio
Present Value Cost Over SO Years
Diesel Generation
Tyee Lake
Savings
Savings/Incremental Capital Investment
$171,4S2,000/83,236,000 = 2.06
=
$330,293,000
1S8,841,000
171,4S2,000
= $2.06 savings per dollar of capital investment
l/ First 20. year~ o.f Tyee Lake. project operation.
2J From Exhibit 3-3.
1/ Capital cost estimate without interest during construction,
emergency and replacement reserves, bonds, fees or other
capitalized project financing costs.
A) See assumptions in Attachment 1 for calculation of present
value of diesel generation capacity costs.
3-57
Based on the comparative c~sts between the diesel base case
and_Tyee, Tyee is estimated to have a present value savings of
approximately $0.141 per incremental dollar of capital investment
over the first 20 years of operation. Over the 50 year operation
of Tyee it is estimated to have a present value savings of $2.32
per incremental dollar ?f capital investment.
These values can be compared to the savings per dollar
of capital investment of any other project for purposes of
establishing a region-wide or statewide economic priority of
development on the basis of economic return on the State's
investment.
3-58
ASSUMPTIONS FOR TYEE PROJECT
ECONOMIC ANALYSIS
Attachment 1
The following is a description of the assumptions used to
prepare alternative economic analyses of Tyee as compared to
continued diesel generation.
Method of Calculating Project Costs
In th~ Tyee report, bhe economic analysis of the Tyee project
was performed assuming four different electrical energy demand
growth scenarios and several financing plans. In this analysis, a
single load growth scenario (Case C from the Tyee Report) was
chosen. This forecast is the "expected scenarion from the Defi-
nite Project Report.li/ In the analysis conductd for this example,
the entire capital cost of Tyee is assumed to be financed a~ 10
percent over 35 years, while the cost of additional diesel genera-
tion capacity is assumed to be financed at 10 percent over 20 years
(for each increment of capacity addition).
The inflation estimate of seven ·percent per year from the Tyee
Report was applied to show how the cost of energy from each alter-
native changes over time. The middle fuel escalation scenario from
the Tyee Report assumes that fuel escalates at 2.6 percent above
the rate of inflation and was applied in this analysis. No load
growth, inflation, or real escalation in fuel was assumed after the
twentieth year of analysis, consistent with the Tyee Report assump-
tions.
The cost of the diesel generation alternative in this
analysis. was calculated by the same method used in the Tyee
Report. First, the diesel capacity required under Case C to
augment existing hydroelectric and diesel generation capacity was
estimated. The annual debt service for diesel capacity was
then astimated over the 50 year study period, assuming 20 year
lives for diesel generators and that investments in diesel
3-59
capacity are made in every fifth year to meet the projected load
growth for the next five years. The cost of fuel and operation
and maintenance were estimated consistent with the assumptions of
the Tyee Report, except that inflation was added.
The Tyee Report anticipates that some of the waste heat from
diesel generation can be used to heat buildings in Petersburg,
thereby displacing fuel oil. The fuel savings from waste heat
utilization was credited against th·e cost of diesel generation in
the Tyee Report for Load Cases A and B. For use in this sample
analysis, this fuel savings value was estimated for Load Case C
using the same procedure as was used in the Tyee Report for Cases
A and B. The annual capital charge, fuel expense, operation and
maintenance and waste heat fuel savings were then combined to
calculate the net annual cost of the diesel generation alterna-
tive to Tyee.
The total capital requirement for development of Tyee and
the 0 & M, insurance and repair and replacement expense
were calculated in the same manner as in the Tyee Report. The
annual cost for diesel generation and for Tyee were then
discounted to establish a present value and summed over 20 years
and over 50 years. A summary of specific assumptions made in
this analysis are as follows:
Assumptions
General:
0
0
0
All assumptions are consistent with the Tyee Report
Inflation rate of seven percent
Interest rate for financing of ten percent (three
percent real escalation above seven percent assumed
inflation ratej
Electrical Energy Demand Forecasts:
0 Based on Load Case c.
0 No load growth after 2003 (the 20th year of analysis).
Diesel Generation:
0 Capacity
3-60
0
0
0
No capital cost is assumed for existing capacity.
Capacity retirements are scheduled consistent with
the Tyee Report.
Investment in new diesel generation capacity is
made at five year intervals.
Costs and Financing
Investments before 2003 are made at ten percent
interest and at three percent thereafter over 20
years (inflation of seven percent is removed from
cost projections after 20 years).
Capital cost is $730/kw in 1981 and is escalated
at the inflation rate.
Operation and maintenance expense is 2.2 cents/kWh
in 1981 and is escalated at the inflation rate.
Diesel fuel cost is $1.10/gallon in 1981 and is
escalated at a 2.6 percent real rate.
Operation
Capacity factors assumed are consistent with the
Tyee Report.
Each gallo? of fuel is assumed to generate 12.6
kWh.
Diesel generation capacity is assumed to have a 20
year life.
Petersburg waste Heat Utilization Credit
While total electrical load growth is given for
each case in the Tyee Report, Petersburg's share is
given only for Cases A and B. That share under
Case C is estimated in this analysis by assuming
that the relationship under Case B between
Petersburg's load growth and total load growth is
constant.
The waste heat utilization efficiency assumed in
the Tyee Report is applied in this analysis.
The waste heat utilization capital cost and system
life assumed in the Tyee Report are used here. The
capital cost is escalated with inflation.
The operation and maintenance expense assumed in
the Tyee Report is applied here, adjusted for
inflation.
,•
3-61
Tyee Lake Hydroelectric Project
0
0
0
The total completed construction cost in 1984 dollars
used in the analysis is $103,700,000.
The project is assumed to be fully financed with tax
exempt revenue bonds at ten percent over 35 years.
Total Capital Requirements, the Reserve Fund, Financing
Expense, Insurance Expense, Administration and General
Expense, Emergency Maintenance and Replacement, and
Earnings on Reserve Fund are calculated in the same
manner as in the Tyee Report.
Calculation of Diesel Generation Present Value Capital Costs
0
0
Diesel capacity capital outlays are (in thousand
dollars) estimated as follows:
1990 $ 6,643
1995 17,973
2000 14,784
2010 17,127
2015 33,043
2020 19,376
2030 17,127
To develop present value capital costs consistent with
the Authority's assumption of zero inflation after 20
years, all costs incurred in the first 20 years are
discounted at ten percent and after 20 years at three
percent (ten percent financing rate less seven percent
inflation) •.
3-62
APPENDIX 3-B
ALTERNATIVE METHOD OF ANALYZING
REGIONAL POWER SUPPLY ALTERNATIVES
Introduction
The selection of power supply projects for design and con-
struction by the Authority and the State Legislature has, in most
cases in the past, been based on the present value cost of a single
project as compared to the cost of supplying an equivalent amount
of energy from a thermal base case. Evaluating a single project as
an alternative to thermal capacity may be suitable when one project
meets all of the incremental power supply needs of a system.
Generally, however, such an approach is limited to small utility
systems. In the case where energy requirements in a service area
exceed the generation capabilities of a single project, or where
several small projects are alternatives to a single larger project,
this method of separately comparing individual projects to the same
base case makes the comparison of the various alternative projects
difficult. The recent completion of an analysis of alternative
power supply plans in the Railbelt provides the Authority with a
planning tool which represents a major step towards analysis of a
power supply system rather than evaluating the relative merits of
an existing thermal system and a specific power project.
The following presents some considerations for augmenting the
Railbelt power system analyses which have been ·conducted to date
with regard to (a) the selection of · alternative power supply plans
for evaluation, and (b) comparison of alternative supply plans.
3-63
Current Methods of Evaluating Railbelt
Power Project A+ternatiyes
The extent of evaluation of alternative power supply plans
to serve the Railbelt Region has basically been the alternatives
considered explicity in the Susitna Project feasibility study,
and the Railbelt Electric Power Alternatives Study (Railbelt
Study) •
The Railbelt Study used a sophisticated generation planning
model. The specific assumptions and methods used in that model
were not evaluated in detail for purposes of this review. The
method in which the model was applied and the results presented are
evaluated in a general manner for purposes of identifying some
alternative ways of applying such a model.
The susitna study of alternatives displayed a present value
analysis of the susitna Project alternatives, the "all thermaln
base case which includes coal and gas turbine additions to existing
thermal capacity, and the thermal base case with the Chakachamna
Hydroelectric project in lieu of.susitna.
The Railbelt Study reviewed several different plans which are
then summarized as follows and shown on .Exhibit 3-5.2.5./
0
0
0
Plan lA -Base Case without Susitna
Non-thermal alternatives in this plan include
Chakacharnna, Allison, and Grant Lake hydroelectric
(approximately 345 MW of additional hydroelectric
capacity).
Plan lB -Base Case with Susitna
This plan deletes· Chakachamna, Grant Lake, and
Allison hydroelectric projects and adds Susitna.
Plan 2A -High Conservation and Use of Renewable
Resources
This plan assumes lower energy demand due to
conservation, with a total of approximately 630 MW
of new hydroelectric capacity without Susitna, a
large wind energy conversion system, and solar and
wood fired space and hot water heating.
3-64
0
0
Plan 2B -High Conservation and Use of Renewable
Resources with Susitna
Same plan as 2A, except Susitna replaces all other
new·hydroelectric projects (other than Bradley
Lake).
Plan 3 -Increased Use of Coal
No new hydroelectric projects other than Bradley
Lake are included in this plan nor any other new
renewable energy resource projects.
Annual average energy costs in 1982 dollars and levelized
energy costs were used to compare the plans in the Railbelt
Study.~ By comparison, the present value life cycle cost method
was used to evaluate alternatives in the Susitna Feasibility Study.
Of the two analyses, the methods used in the Railbelt Stuqy most
nearly approximate a system analysis approach which considers
different power supply plans. In the Railbelt Study, several combi-
nations of potential projects were compared to develop an estimated
srstem cost of power for each plan. However, the Railbelt Study
analysis did not compare the different sets of power project
alternatives against the same demand forecasts. The selection of
alternative power supply plans assumed that hydroelectric projects
other than susitna or Chakachamna would only be developed under the
high energy conservation.scenario used in evaluating plans 2A and
2B. Alternative power supply plans 2A and 2B assumed a lower
energy demand than Plans lA and lB.
Alternatives for Augmenting the Analysis
of Power Supply Plans
The Railbelt Alternatives Study has compared various
combinations of alternative power supply projects with and without
Susitna. The average cost of power for the Railbelt was analyzed
for each alternative power supply plan. As discussed above,
however, the comparison of alternative supply plans which are
presented in the study did not assume the same levels of demand in
each case. By assuming that the more extensive list of
hydroelectric project alternatives to Susitna in Plan 2A would only
be developed under the scenario assuming high conservation
3-66
implementation (hence lower demand) and maximum use of renewable
resources, there has not been a true comparison of the entire list
of potential hydroelectric projects to the "with Susitna" scenario.
The Plan lA power supply resources (the "without Susitna"
plan) excludes approximately 283 MW of hydroelectric capacity which
is included in the Plan 2A r~sources (this is the combined capacity
of the Browne, Keetna, Snow, and Strandline projects, using the
capacity estimates provided in Table 4.2 of the Railbelt Electric
Power Alternatives Study Feb. 1982 Comment Draft). Including the
283 MW of additional hydroelectric capacity from these projects in
Plan lA to compare with Plan lB using the same level of demand
forecast for both plans would appear to be a more useful method to
compare an alternative plan to a "with susitna" plan. This
approach would allow the comparison of a combination of as many
smaller hydroelectric projects as are potentially available to
match (to the extent possible) the capacity and energy which would
otherwise be met by Susitna, using the same energy demand forec~st
in each case.
The Authority could also consider varying from its established
standard of utilizing a base case analysis method for reviewing
alternative projects in the Railbelt study area. In evaluating the
generation additions to meet future energy ~equirements which
exceed total existing and committed project energy production, a
base case approach does not necessarily have to be taken. Each set
of alternative additions to the existing and committed system can
be evaluated on an equal basis. Although, if a plan was previously
selected as a preferred or most likely plan, it could be selected
as a base case for purposes of comparing alternatives •. The
application of a generation planning model does not require this,
however.
3-67
APPENDIX 3-C
REYIEW OF POWER MARKET AREA ANALYSIS
Introduction
One of the basic problems which has been encountered in past
reconnaissance and feasibility assessments of many of the power
projects to serve communities in the bush and Southeast Alaska has
been the limited evaluation of alternative definitions of the
service or market area. Examples where this problem has been
J
apparent are the reconnaissance study of the Kake-Petersburg
Transmission Intertie and the reconnaissance study of power supply
alternatives for the bush community of Galena. In both of these
analyses, considerable uncertainty as to project feasibility has
been encountered due to questions regarding the area and the corre-
sponding electrical demand to be served by the projects being
studied. One of the sources of this problem has been.the project-
oriented approach to reconnaissance and feasibility studies. By
focusing early in the evaluation process on the feasibility of
specific projects, considerati~n of the power supply system as a
whole can be under-emphasized.
In addition to the above projects, the Black Bear project is
used as an example where, despite earlier consideration of
interconnection alternatives, there has been a need to reconsider
the possibility of including additional villages in the system to be
served by the project. It is important to note that in recent
studies such as the Bristol Bay and Bethel area regional power
plans, the Authority has taken more of a power. systems and market
area approach by considering regional and sub-regional possibili-
ties for interconnection to serve several villages from "central"
projects. Adoption of this approach as a standard evaluation
procedure, where it is warranted, should reduce some of the prob-
lems described herein.
3-68
This appendix provides a brief description of three studies
which have been conducted for the Authority. These studies are
presented as examples of some of the problems which have been
encountered in the power supply planning process both when inter-
connection prospects are not evaluated extensively early in the
process and when conditions durng the planning process change prior
to project construction (the latter situation was encountered in
the Black Bear Project). Alternative planning approaches which
could minimize such problems are described for each study as
examples. It is important to note that on the Black Bear hydro-
electric project and the Kake-Peteresburg Intertie project
additional analyses appear to be either underway or planned to
address some of these issues. The purpose of these brief case
studies is to present examples of how early recognition of the need
to fully evaluate alternative power market areas would increase the
efficiency of the power supply planning effort, and how uncertain-
ties regarding the market area to be served can complicate the
project authorization process.
' Kake-Petersburg Transmission Intertie
The community of Kake is a city of 5 70 people on Kupreanof
Island in southeastern Alaska. A reconnaissance-level report was
completed in January 1981 on the potential for constructing a
24.9 kV transmission intertie between Kake and Petersburg for
power from the Tyee Lake hydroelectric project. The two sources
of power for Kake are the Tlingit-Haida Regional Electric
Authority (THREA) and diesel generation at Kake Cold storage
which generates for their own use. The 1981 energy generation
was 1,525 MWh for THREA and 501 MWh for Kake Cold Storage.
Recently installed capacity is 1,600 kw at THREA and 975 kw at
Kake Cold Storage. ·
A forecast including Kake Cold Storage requirements was
prepared for the study. However, in conducting the present value
life cycle cost analysis (present value analysis) for alternative
projects, the analysis assumed that Kake Cold Storage will continue
to self-generate, although Kake Cold Storage has requested to
puprchase power from THREA.
3-69
The reconnaissance study provided present value analysis
results for four alternatives, as follows, excluding the Cold
Storage generation costs.
Base Case -Diesel Generation
Kake-Peteresburg Intertie
Cathedrai Falls Hydro
wood Fired Generation
Present value Cost
$13,900,000
14,700,000
14,900,000
17,200,000
Although alternative economic analysis methods may indicate
otherwise, based on present value analyses the first three alterna-
tives are nearly of equal economic desirability. The addition of
the Cold Storage electrical demands to the system to be served by
the intertie would increase the total load served by approximately
one-third. Adding approximately one-third to the electrical demand
to be served by either the Cathedral Falls project or the intertie
would likely provide substantially different relative present value
estimates.
An additional .local concern with the study was the demand
forecast. Annual load growth estimates of approximately two
percent were adopted as a most likely forecast. Local opinion
indicated that a higher rate of growth was hoped for, if not
likely, based on economic growth and development in the area.
Since the cost of a transmission intertie is nearly all fixed
capital cost, the cost per kwh for the intertie project as
compared to diesel generation is highly sensitive to the size
load served. Early consideration of all loads potentially served
by the project and a range of load growth rates would have
provided a more complete review of the range of comparative
economics between the alternatives.
The accommodation of local opinion regarding load growth in
selecting alternative power supply plan scenarios can be a budget
concern. Often local opinion regarding high demand growth ·
possibilities is founded more on desire than probability of such
growth occurring. The extent to which the Authority evaluates
higher demand projections will influence the cost of reconnaissance
3-70
and feasibility studies. However, if analyses using highe~ energy
demand levels do not change the relative economics of project
alternatives studied, then later local questions or criticisms that
a preferred alternative was foreclosed due to a "low" demand
assumption can be avoided. If such early consideration avoids a
later reevaluation, the net result can be a savings in time and
expense.
A study of the intertie is currently being augmented by the
Authority to address these alternative considerations to form a basis
for decision. Incorpora~ing such considerations at the outset
would save substantial planning time and expense.
Black Bear Hydroelectric Project
The Black Bear hydroelectric project on Prince of Wales
Island west of Ketchikan is a 6,000 kw project for which a
detailed feasibility study was conducted in 1981. A FERC license
for the project was filed in early 1981 and approximately
$2.4 million has previously been appropriated for feasibility,
licensing, and design in 1981 and 1982.
The project as proposed was planned to serve the utilities
in the villages of Craig, Klawock, and Hydaburg. Recently,
requests have been made to also interconnect the project to serve
Thorne Bay, Hollis, and a new u.s. Forest Service camp proposed at
Polk Inlet on the island. As with most hydro~lectric projects
under development in Alaska, the near-term energy costs of the
Black Bear project may have to be subsidized or debt service pay-
ments restructured to market the power. The extent of such subsidy
or other financing assistance will be highly sensitive to the
electrical loads served by the project. Since the Black Bear
project is projected to be capable of providing more energy than
the villages of Craig, Klawock, and Hydaburg are expected to
require in the early years, the addition of other communities to
the system served by the project could significantly impact project
revenue, and therefore affect the amount of state financial assis-
tance required.
The potential for including Thorne Bay and Hollis was
considered preliminarily in the previous studies conducted for the
3-71
Black Bear project. At that time, the costs of interconnection
were considered to be in excess of the benefits gained from
increasing the load growth served by the project. Recent changes
in population growth at Thorne Bay due to federal land transfers
has changed the conditions from those existing when the studies
were-previously conducted. The Authority currently plans to review
the feasibility of-interconnecting Thorne Bay and Polk Inlet in
early 1983.
The impact of adding Thorne Bay and Polk Inlet to the area
served by the project is unknown. It is possible, however, that
the addition could impact overall project economics such that the
financing arrangements (the amount of State funding needed to make
the project power marketable in the early years of operation) may
differ depending upon whether these loads are served by the pro-
ject. The impact of such revisions to planning assumptions must be
considered as part of the final authorization process and as part
of the selection of a financing plan if the changes significantly
impact project economics.
Galena Reconnaisance Study
As part of the Authority's Village Energy Reconnaissance Pro-
g-ram, a reconnaissance-level analysis of electrical and thermal
energy demands and supply alternatives was conducted for the Vil-
lage of Galena. This study is another example of the importance of
considering opportunities for interconnection early in power supply
planning.
Galena is a village with a population of approximately 805
people located on the Yukon River about 270 air miles west of
Fairbanks. Electrical energy is provided by a private utility
company with a. total diesel electrical capacity of 635 kw. The
u.s. Air Force Base at Galena supplies its own electric power from
four diesel units with a total capacity of 2,000 kw. Peak demand
for the private utility system is 300 kw and the Air Force Base
peak demand is approximately 970 kw. Based on 1980 annual energy
use data, the private system produced 1,000 MWh of energy for the
village and the Air Force produced approximately 6,000 MWh of
electrical energy for the base.
3-72
summary of Study Results
The Galena reconnaissance study of electric power supply
alternatives was bas~d on a forecast of the village energy needs
only. The Air Force Base requirements were assumed to be con-
stant, but were not included in the total demand estimates used
to evaluate alternative power supply projects for the village.21/
The peak power demand and the annual energy requirements of the
village are projected to increase from approximately 300 kw to
850 kw and 1,100 MWh/yr to 3,000 MWh/yr, respectively, between
1982 and 2001 in ~he reconnaissance st~dy •
The study estimated the present value life cycle cost of the
following three alternative power supply plans to meet the Galena
electrical power requirements during the period from 1982 through
2041.
Base Case
This plan is the continued use of a diesel-based cen-
tral utility system with waste heat recovery to meet some
local thermal energy requirements.
Alternative Plan A -Kalakaket Hydroelectric Project
This alternative involves developing a run-of-the-river
hydroelectric p~oject on Kalakaket Creek. The capacity of
the project is not stated in the report, but its annual
energy generation is estimated at 1,729 MWh. The plant
would not operate from November through April due to ngla-
cieringn of the .river. ~Therefore--the same-diesel capacity
additions projected for the base case are assumed to be
required in this case to me•t the winter peak demands and
the winter energy requirements.
The hydroelectric project would produce more energy
than than the village could utilize when it operates. The
study therefore assumed any excess energy could be marketed
~ to the Air Force Base.
3-73
Alternative B -Melozitna Hydroelectric Project
This alternative involves constructing a 20 MW or
larger hydroelectric project on the Melozitna River to serve
Galena and five other villages in the region. There was
strong local preference for eval~ation of such a project.
To evaluate this project, the regional potential power
requirements, including the Air Force Base at Galena, were
projected. To compare the cost of this plan for Galena
relative to the base case plan the total project costs were
prorated on the basis of Galena's share of energy from the
project.
The annual total power cost and power cost per kwh were
estimated for each alternative and the present value life
cycle cost of each alternative was calculated, producing the
following results:
60 year
Present Value
Alternative Life Cycle Cost
Base Case -Diesel Gene~ation $20,220,000
Alternative A -Kalakaket Hydro. $22,463,000
Alternative B -Melozitna Hydro. $46,263,000
Based on this analysis, the base case diesel generation
with waste heat recovery was selected as the most
economic alternative. The study indicated, however,
that additional evaluation of the regional Melozitna
project might be warranted. It was recommended that such
a study focus on a more detailed analysis of regional
power needs, the configuration and cost of the
Melozitna Project and transmission interconnection
opportunities and costs.
3-74
Alternative Planning Considerations
Preliminary consideration was given in the study to inter-
connecting the Galena Air Force Base utility system (2000 kw
capacity with a 970 kw peak load) with the private utility's
system which serves Galena (635 kw system with a 300 kw peak
load). This option was dismissed without any quantitative analy-
sis due to uncertainties over the issues associated with power
sale or exchange arrangements between a federally owned system
and the privately owned system.
The evaluation of potential savings from interconnecting
existing systems to share excess capacity, defer new capacity,
and share in fuel efficiency gains is an alternative which can be
evaluated in a· reconnaisance study regardless of the availability
of preferred renewable resource projects. In the case of Galena,
the Air Force Base operates larger diesel generators than those
serving Galena. To the extent the larger plants can be operated
nearer to their rated capacity, it is likely that fuel efficiency
would increase, as compared to operating the base's plants at
lower output and operating the smaller private utility's equip-
ment at partial output.
Perhaps a more significant consideration is that the com-
bined capacity of the Air Force Base plant and the private
utility's system is 2,635 kw and the combined peak demand (assu-
ming the peaks for both systems would be simultaneous) is
currently 1270 kw. If the back-up generators from the local
school and other private generators were added, the excess
reserve capacity is even greater. Combining these generating
facilities into an interconnected system would likely defer capa-
city additions for several years.
As a specific example, the proposed expansion plan described
in the report calls for a new 440 kw .unit to be added in 1986 at
a 1981 cost of $352,000. Interconnection might result in elimi-
nation or substantial deferment of this requirement. The costs
of interconnection, the operating characteristics of the two
utilities, the fuel efficiency of the respective power plants and
the respective load growth of the Base and the Village would have
3-75
to be evaluated to determine the relative economics of this
option as compared to continued isolated operation of the two
systems...
The purpose of this review is to emphasize that if the power
supply planning process is oriented towards evaluating and devel-
oping new generation projects, then lower cost modifications to
existing systems to increase operating efficiency through inter-
connection may be overlooked. Furthermore, if such options are
not evaluated early in the process--at the reconaissance level--
it is likely that the concept will not receive attention later,
even when no other options are found to be superior to continua-
tion of the status quo.
It should be noted that the opportunities for intercon-
nection of electrical loads which are currently isolated are not
necessarily widespread in Alaska. Small villages in isolated
areas have few opportunities for interconnection. Furthermore,
it is common for bush communities to be reluctant to accept the
idea of interconnection to a "central utility system" since the
solitude of bush community living is one of the fa~tors which
draws people to the bush. Therefore, in many cases, the issue of
interconnection options may be academic. However, for communi-
ties where power costs are of vital concern, and where local
economic growth is consider~d a desirable (if not achievable)
goal, the prospects for interconnection should not be discounted
without explicit consideration of such alternatives.
Where interconnection opportunities have been prelim-
inarily evaluated and dropped during reconnaissance studies, it
would be helpful to fully document the assumptions used to make
such a recommendation to allow for future reference if conditions
change or the issue is raised during the authorization process.
The Authority's recent.efforts to reevaluate interconnection
opportunities in situations such as the Black Bear project appear
to be steps in this direction.
3-76
SECTION 4
REVIEW AND ASSESSMENT
OF WHOLESALE POWER
RATE STRUCTURE
INTRODUCTION
This section of the report provides the results of our work
under Task 4.0. This work addressed issues and alternatives
relating to the efficiency and equity of the present rate
structure. Our approach to this work utilized the present rate
structure provided under HB 9 as a base case. Our evaluation of
the present rate structure, as well as the previous rate structure
provided under SB 25, was made on the basis of the following
criteria:
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0
0
0
0
Efficiency in providing a stable flow of revenues
sufficient to cover costs over a relevant range of
variations in load
Consistency with conservation goals
Consistency with policy goals other than conservation
Equity in the distribution of costs
Equity in the distribution of benefits of State funding
Iri addition we have considered the potential impact of the
HB 9 rate structure on the Authority's financing as well as the
more general question of financ:i,.ng con~J.derations in establishing
the wholesale power rate structure. ·
4-1
GENERAL PRINCIPLES FOR WHOLESALE
POWER RATES
The bulk of the general literature on the subject of
electric utility rates is dedicated to retail rates for sales
to the ultimate consumer as opposed to wholesale rates. Rates
established by the Authority pursuant to the rate directives
provided by the Alaska Legislature are not, in themselves,
utilized in the billing of ultimate or retail customers. Rather,
the Authority's rates form the basis of billings to its utility
customers. The cost of power purchased by those utility
customers becomes one component of the total cost which must
be recovered through retail rates.
For the most part, wholesale rates of electrical utilities
are under the jurisdiction of the Federal Energy Regulatory
Commission (FERC), a federal agency. The notable exceptions to
this are the rates of publicly owned utilities or public agencies
which market the power at wholesale. Statutory rate directives
governing wholesale rates under the FERC jurisdiction are provided
primarily by the Federal Power Act (16 u.s.c. 791 ~ ~).
The basic principles governing the establishment of rates
and charges subject to the FERC jurisdiction are as follows:
All rates and charges made, demanded, or received by
any public utility for or in connection with the
transmission or sale of electric energy Silbject to the
jurisdiction of the Commission, and all rules and
regulations affecting or pertaining to such rates or
charges shall be just and reasonable, and any such rate
or charge that is not just and reasonable is hereby
declared to be unlawful. (16 u.s.c 824d(a))
No public utility shall, with respect to any
transmission or sale subject to the jurisdiction of the
Commission, (1) make or grant any undue preference or
advantage to any person or subject any unreasonable
difference in rates, charges, service, facilities, or
in any other respect, either as between localities or
as between classes of service. (16 u.s.c. 824 d(b))
The two most important rate directives provided by the Federal
Power Act which have generally guided the FERC's review of
4-2
wholesale power and wheeling rates are, therefore, that they be
based on the cost of providing service and that they be non-
discriminatory.
Over the years, the Federal Government, through the U. s.
Army Corps of Engineers (Corps) and the Bureau of Reclamation of
the Department of Interior (Bureau) have constructed a number of
hydroelectric generating facilities. For the most part, these
have been part of multipurpose projects primarily constructed for
flood control, reclamation and irrigation purposes. Power from
these projects is marketed by federal power marketing agencies
(FPMA) within the Department of Energy.
Rate directives governing the establishment of rates for the
sale of federal power which is surplus to the-requirements of the
projects from which it is generated have been provided by Congress
both in statutes relating to the projects and in those creating
Bonneville Power Administration, the largest of the FPMA.
The language of these rate directives generally provides for
the disposition of federal power in such a manner as to encourage
the most widespread use at the lowest possible rates to consumers
consistent with sound business principles. The other most common
language in the several statutes provides that rate schedules
shall be drawn having regard to the recovery of cost of producing
and transmitting electric energy, including the amortization of
the capital investment allocated to power over a reasonable
_period of years.
Although the words of the Federal Power Act which govern
wholesale rates of utilities regulated by the PERC are slightly
different than those of the statutes that provide rate directives
for the disposition of federal power, they both mandate that rates
should be based on cost.
It is noted that the general rate directive language of the
statutes relating to the Authority is very similar to that con-
tained in the federal statutes. Neither SB 25 nor HB 9 changed the
language that provided "the Authority • • • shall sell the power or
cause the power to be sold at the lowest reasonable prices which
cover the full cost of the electricity or service ••• " (AS
44.83.090). In plain language, this provides a cost based rate
standard.
Although, as previously discussed, most of the literature on
the subject of rates pertains to retail rates, several principles
certainly have application to wholesale rates. Bonbright in
·his Principles of Public Utility Rates, sets forth eight criteria
of a "desirable rate structure". These are:
0
0
0
0
0
0
0
The related, "practical" attributes of simplicity,
understandability, public acceptability and feasibility
of application.
Freedom from controversies as to proper interpretation.
Effectiveness in yielding total revenue requirements.
Revenue stability from year to year.
Stability of the rates themselves, with a minimum of
unexpected changes seriously adverse to customers.
Fairness of the specific rates and the apportionment of
total costs of service among the different customers.
Avoidance of undue discrimination in rate relationships.
Efficiency of the rate classes and rate blocks in
discouraging wasteful use of service and in the control
of the relative use of alternative types of service
(on-peak versus off -peak).
In addition to the considerations of equity and cost
recovery, it has always been recognized that utility rates must
be developed on a basis that is consistent with established
public policy. This is particularly true in the case of rates
for a publicly owned utility.
In any consideration of utility rates, it is important to
draw a distinction between rate level and rate structure. Rate
level is governed by the total revenue requirement of the
utility. This is the amount that must be raised or in the case
of regulated utilities, the amount that is allowed to be raised,
from rates. Rate structure, on the other hand, relates to the
distribution of the revenue requirement between customer classes
and individual customers within the same customer class. These are
important policy considerations that must be addressed in rate
directives provided by Legislatures.
4-4
EVQLUTION OF AUTHORITY WHOLESALE POWER RATES
Although not actually funded and staffed until 1978, the
Authority was created in 1976 (SCS CSHB 779 Ch 278 SLA 1976)
for the purpose of acquiring, financing, constructing and
operating hydroelectric and fossil fuel generating projects.
Initial Rate Directives
HB 779 created the Authority in 1976. Included in its powers
was authorization to enter into contracts for sale of power. The
authorizing legislation established individual power rates for
each project whose rate would provide power at the lowest possible
price while covering the full cost of generation, capital and
operation and maintenance charges, plus a fair cost of transmis~
sion.za/ Thus, each c~ntract for the sale, transmission and
distribution of power from a particular project was unique in that
it was determined by factors specific to that project. Rates which
were fixed initially in the contract could be "adjusted from time
to time on the basis of true cost data."
Contracts to sell power were subject to review by the Alaska
Public Utilities Comission (APUC) and this led to some confusion
regarding rate setting jurisdiction.
1978 Amendments
The question of rate setting jurisdiction was settled by
legislation enacted in 1978 (SCS CSHB 442 Ch 156 SLA 1978).
This bill established that the Authority would not be subject to
the jurisdiction of the APUC, and that the Authority likewise
would have no jurisdiction over the services or rates of any
public utility within the domain of the APUC.
In addition, the 1978 legislation modified the requirements
concerning power sales contracts. It mandated that the Authority
provide a method by which municipal electric, rural electric,
cooperative electric, or private electric utilities and regional
electric authorities could secure a reasonable share of power
4-5
generated by a power project, or any interest in a project.
Furthermore, it stated that "power shall ••• be sold at the
lowest reasonable prices which cover the full cost of the
electricity or services." W
SB 25 Amendments
In 1981 the Legislature made significant changes in statutes
governing the Authority (FCCSSB 25 CH 118 SLA 1981). SB 25 created
the Energy Program for Alaska (Energy Program) and made significant
changes in the wholesale power rate structure for projects which
were included in that program. Individual power rates for each
project were replaced with a single wholesale power rate. This
applied to all projects which were acquired or constructed as part
of the Energy Program and funded by appropriations from the Power
Development Fund.
The rate, applicable at the busbar of the power project, was
to be computed by the Authority annually and was to equal the rate
estimated to produce revenue that would be sufficient to pay opera-
tion, maintenance, and equipment replacement costs; plus debt ser-
vice; plus monitoring expenses incurred on all of its power pro-
jects. It also specified the terms and conditions of power sales
leases.
The rate language provided certain consequences if the legis-
lature did not appropriate at least $5 billion to the Power Develo-
pment Fund by 1986. (This provision has become known as the
"Susitna Blackmail Clause" because it did not specifically require
the Legislature to appropriate funds, which would be unconsti-
tutional, but it did specify what would happen if it did not.) If
this was not done, the ensuing wholesale rate, beginning in 1986,
was to be: the greater of 10 percent of the amount the Authority
had invested in the power projects or the rate'estimated as neces-
sary to produce revenue sufficient to cover project costs as
described above. Lastly, this bill stipulated that the Legislature
may, by law, annul or change the Authority's wholesale power rate
for sales of power.
4-f\
1982 Proposed Changes
Early in 1982, two bills to amend SB 25 were introduced.
HB 655 was introduced in January at the request of the Governor.
In March, the Resources Committee of~ered a substitute bill {CSHB
758). Both contained language which would have altered wholesale
power rate structure in Alaska. The following description of the
1982 proposed changes is presented in a summary form which high-
lights key aspects of these bills. A more technical account is
provided in Appendix 4-A.
HB 655 proposed to change the statewide wholesale power rate,
provide an adj~stment mechanism when miscalculations were disco-
vered, create a new fund for the Authority, and utilize an alterna-
tive formula for d~termining the return to the State on its invest-
ment.
Under HB 655 the single statewide wholesale power rate would
have been replaced and ·each project would have had its own rate.
The wholesale power rate would have been calculated based on
project costs identical to those of SB.25, except that rates could
have been influenced by loan repayment obligations for those
.Projects that used the Power Project Emergency Maintenance Fund
{which this bill would have created).
Furthermore, this bill would have removed the "Susitna Black-
mail Clause" entirely. It proposed a method whereby the State
would have been repaid the entire initial investment in equal
installments through yearly rate increases over a 33 1/3 year
period with each period's principal adjusted for inflation. The
amount repaid to the State would have been escalated by a factor of
1.0 plus the rate of inflation {calculated as the average rate of
inflation over the preceding 33 years). -This procedure would have
resulted in the State being repaid its investment in dollars of
equal purchasing power. This bill differed from SB 25 in that it
would have required repayment of the State's investment.
CSHB 758 (HB 758) concentrated its rate reform proposals on
three major areas: rate structures; the relationship, and proce-
dures for the Authority and the APUC; and the method by which the
return to the State would have been calculated.
4-7
Like HB 655, HB 758 would have required that a separate whole-
sale power rate be. established for each power project. Both bills
would have included the same components for calculating the whole-
sale power rate, except where the return to the State was concerned.
The area which this legislation dealt with was the method and
timing of repayment to the State of it~ capital.investment in power
projects under the Energy Program. Like HB 655, this bill would
have deleted the "Susitna Blackmail Clause" and provided a repay-
ment schedule for money contributed by the State. However, under
this proposal, the repayment period would have been 33 1/3 years or
a period equal to 3/4 of the life of the project, whichever was
less.
HB 758 would have calculated the inflation rate differently
and applied it to more i terns than HB 655. This bill would have
directed the Authority to consider inflation over two different
time horizons, near and long term, and to use the lesser of the two
in insure that the value, in terms of "purchasing power" of the
State's capital outlay was preserved over the repayment period.
This bill also attempted to compensate for inflation's effect
on the wholesale power rate over time. The inflation rate appli-
. cable would have been calculated as outlined previously and the
yearly payment adjusted accordingly. However, this bill also would
have escalated the wholesale power rate itself once every ten years,
to "catch up" in a sense.
One unique provision of HB 758 was that it would have provided
a consumer rate structure consisting of at least three rates.· The
utility would have been expected to implement an "inverted" rate
schedule at the retail level, with the lowest rate being an "equity
rate". This change in rate structures would have necessitated the
APUC's intervention in the rate setting process so that they could
hold public hearings before rates were changed.
Finally, both HB 655 and HB 758, like SB 25, would have
allowed the Legislature to annul or change the wholesale power rate
by law.
4-8
•
HB 9 Amendments
CCSHB 9 (CH 133 SLA 1982), which evolved as a compromise to HB
655 and HB 758 was enacted in May 1982, and had a significant
effect on wholesale power rate structure. The ~ajor areas changed
by this legislation were in the type of wholesale rate, and in the
debt service share of each project.
HB 9 replaced the single wholesale power rate established
in SB 25 with an individual rate for each project to be based on
0 & M and inspection costs, plus the individual project's propor-
tionate share of the debt service on State bonds and loans for all
power projects in the Energy Program. The wholesale power rate was
to be computed annually by~ the Authority~ but it could be calcu-
lated more frequently if necessary.
Under this bill, transmission interties are also allowed to
have individual rate structures. This provision was included to
prevent high-priced interties from pricing themselves out of use in
higher priced utility service areas. This bill also included a
clause which made allowances for interties that cease to function
as separate projects. If the Authority determined that an inter-
tie had effectively become a part of another power project, its
special status as an intertie with its own rate would be termi-
nated.
Unlike HB 655 or HB 758, HB 9 maintained the provisions of the
"Susitna Blackmail Clause" described earlier. What it did add,
however, was a clause whereby the debt service on State loans and
bonds for all projects in the Energy Program is allocated to each
power project on the basis of its "proportionate share" of that
debt service. The proportionate share is equal to the State's
investment in the particular power project divided by the State's
investment in all power projects in the Energy Program for Alaska
and multiplied by the debt service on State loans and bonds for all
power projects in the program. The basic intent was to spread the
State investment for power projects more equitably among projects.
This arrangement appeared to be more equitable than totally sepa-
rate rate structures because the formula accounted for project size
and construction efficiency in that it considered the total
4-9
cost of each project relative to the total cost of the power system
when allocating debt service shares.
"To prevent power rates for some projects {primarily Swan
Lake and Lake Tyee) from escalating to excessive levels under
this rate structure, a limit or cap was placed on the debt service
share for projects underway before the effective date of HB 9. The
level of the cap increases by four percent per year to account for
the increased utilization {power sales) of the power projects."W
As explained in the Letter of Intent on Conference CS for
HB 9 (Senate Journal, May 31, 1982):
Subsection (h) of section 16 provides for the phasing-
in of a project's payment of its proportionate share of
all power project debt service. The Legislature
intends, in establishing this "cap" formula, .that.the
weighted average share of debt service be computed by
dividing the total annual debt service of all projects
in the energy program for Alaska by the total annual
electricity sales. An eligible project's share is then
annually raised by 4% above the average until it
reaches its actual share under the system described in
(g), at which point the "cap" for that project
terminates. Thus, in FY 1984, no eligible project
would pay more than 104% of the average share; in FY
1985, no eligible project would pay more than 108% of
the average share; and so forth. The "cap" assures
that the allocation of debt service among projects does
not place an undue burden on those projects which were
begun under the previous hydro financing system.
Further, it is the Legislature's intent that the
difference between an eligible project's share of the
total debt service and the amount paid under the "cap"
shall be made up by the shares paid by all other
projects in the energy program for Alaska for which
debt service is not limited under the "cap."W
Finally, HB 9 provided that the Legislature may annul or
change a wholesale power rate by law, but that if the Authority
has entered into an agreement with bondholders to maintain or
increase the rate, then that rate will remain in effect.
ANALYSIS OF AUTHORITY RATE DIRECTIVES
We have developed a comparative analysis of the significant
provisions of, and actual rates that would be in effect under,
the rate directives provided by SB 25, HB 655, HB 758, and HB 9.
4-10
Comparison of Rate Directive Provisions
A summary comparison of the rate directives under the above
noted legislative bills is provided in Exhibit 4-1 on the fol-
lowing page.
Rate Form
SB 25 provided a "postage stamp" or uniform rate that would
be calculated on the basis of the total costs and.sales related to
all Authority projects. Under HB 9, this. was changed to a project
specific rate. Both HB 655 and HB 758 would have provided project
specific rates. Under HB 9, however, there is a limited equaliza-
tion of debt service between projects which introduces a "flavor"
of a uniform rate for all projects.
We understand that the change from the postage stamp rate to a·
project specific rate was influenced, at least in part, by the
Legislature's concern that cost overruns on projects and relatively
low utilization of the output would adversely affect the rates from
previously constructed projects. In eff~ct, this change was
intended to provide an economic incentive with respect to both the
capital cost of projects and project utilization.
Frequency of Calculation
All of the legislative directives have provided for annual
calculation of rates from the Authority's projects. HB 9 did,
however, add a provision that would allow recalculation of rates
more frequently than annually, as may be necessary.
So long as the sale of energy from the projects is a rela-
tively small portion of the potential average generation, revenue
shortfalls should not be a problem. Once project sales and project
generation capacity are more nearly equal,· there may be situations,
in dry years, when revenue shortfalls might occur. One solution to
this problem would be an adjustment in rates once water conditions
had been determined. There are, however, other approaches to this
problem which are discussed later in thi~ section of the report.
4-11
SUMMARY COMPARISON OF PROVISIONS OF ALASKA POWER AUTHORITY RATE DIRECTIVES
SB 25 HB 655 HB 156 HB2
Rate Form
Postage Stamp X
Project Specific X X X
Frequency of Calculation
Annually X X X X
"As May Be Necessary" X
""' Rate Components I
1-' 0 & M, Replacement, and Inspection Costs X X X X N Debt Service X X X X
Repayment of State Investment X X
Procedure to Compensate for Rate
Estimation Errors from Previous Year X X
Power Project Emergency Maintenance Loans X X
Separate Rates for Inter ties X
Legislative Prerogatives
Can Annul or Change Rate Without Restriction X X X
Constrained by Contracts with Bondholders X
Other
"susitna Blackmail Clause" X X
Inflation Adjustments for:
Wholesale Power Rate X
Repayment of State Investment X X
Tiered Retail Power Rates X
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Rate Components
The various components or categories of costs that make up.
the Authority's revenue requirement under the several legislative
bills are discussed below.
0 and M. Replacement and Inspection Costs
As would be expected, all of the legislation relating
to the Authority's rates provides for recovery of these
costs. A broad interpretation of 0 and M costs would
indicate that they would also include that portion of the
Authority's administrative and general costs that are appli-
cable to operation of projects as opposed to planning and ·
project development. This will become more of a factor as
projects are completed and become operational. With respect
to replacement costs, again a broad interpretation would indi-
cate that a "formula" contribution to a renewal and replace-
ment fund might be included in this component of revenue
requirement. This point is discussed further later in this
section of the report.
Debt Service
Again, all of the legislative bills provided for
recovery of annual debt service which includes principal
payments on outstanding Authority debt (as opposed to State
grants for construction). However, the rate directives are
silent on the question of any coverage of debt service that
might be included. AS 44.83.425 does contain a definition of
debt service that provides for "cash flow necessary to secure
bonds." To the extent that debt service coverage is deemed
"necessary" in bond covenants, this definition does not
preclude the use or need of funds for debt service coverage.
However, the absence of a specific directive creates some
ambiguity. This point is also discussed later in this section
of the report and in more detail in Section 6 under Authority
financing.
4-13
It should be noted that total debt service is included
as an Authority revenue requirement under HB 9, but a provi-
sion is made for a proportional allocation o~ debt service
to individual projects with a cap. This has been discussed
in some detail previously.
Repayment of State Investment
Only HB 655 and HB 758 had provisions whereby the State's
investment in the form of grants in power projects would be
repaid. Neither SB 25 nor HB 9 had such provisions, but they
did include the so-called "Sustina Blackmail Clause". If the
clause was "triggeted", rates might exceed the level required
for operation and maintenance costs and debt service. No
specific language was added specifying that those "excess
funds" would flow back to the State as a repayment of their
investment, but it was assumed that those revenues would be
deposited in the General Fund. This is discussed in greater
detail under the "Susitna Blackmail Clause", in the "Other
Rate Directives" section following.
Procedure to Compensate for Rate Estimation Errors
Again, HB 655 and HB 758 provided a procedure to
compensate for rate estimation errors from the previous
year. No such provision was provided in either SB 25 or
HB 9.
Power Project Emergency Maintenance Fund Loans
HB 655 and HB 758 provided a mechanism for the loan of
funds required for emergency.maintenance. The "Power Project
Emergency Maintenance Fund" was to consist of money appro-
priated by the Legislature. (This subject is discussed in
connection with interim replacements later in this section of
the report.) No similar provision is explicitly provided
under HB 9 nor was it provided under SB 25. However, the
Authority is able to obtain loans from independent sources to
4-14
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cover emergency situations under the "Powers of the Authority"
provisions (AS 44.83.080 (8) and (14)) of current legisla-
tion • .l2./
Separate Rates for Interties
HB 9 specifically provides that a separate rate, distinct
from the rate for any power project, can be established for
interties. We have concluded that what the Legislature had in
mind, specifically, was the Anchorage-Fairbanks intertie. We
believe that such a provision is very appropriate in that
transactions beyond the delivery of power generated from pro-
jects developed by the Authority will take place on interties.
Establishing a specific rate for wheeling service on the
intertie will facilitate such transactions.
Legislative Prerogatives
Under SB 25, HB 655, and HB 758 the Legislature reserved unto
itself the prerogative of annulling or changing a rate established
by the Authority without any restriction. Under HB 9, although
this authority continues, the Legislature recognized that it would
have to be constrained by any covenants or contracts with bond-
holders made in connection with the issuance of Authority revenue
bonds or other debt instruments.
Other Rate Directives
Other rate directives provided by these four pieces of legis-
lation are.discussed below •
"Susitna Blackmail Clause"
As previously discussed, SB 25 and HB 9 both contain
provisions that would increase the rates to all projects if
at least $5 billion is not appropriated to the Power Develop-
ment Fund by 1986. In such an event, the level of rates from
the Authority's other projects V?Ould be set at a minimum of at
A.-lt;
least 10% of the total investment of the State in those pro-
jects. In both cases, the legislation was silent on the
disposition of any surplus funds that might be generated from
a higher rate calculated on the basis of 10% of the investment
in projects. However, it seems realistic to assume that the
' excess funds (those·above 0 & M and debt service costs)
received would be deposited to the General Fund. Constitu-
tional prohibitions against dedicated funds ensure that
receipts not otherwise pledged (this provision applies to
bondholder trust funds and power sales receipts) are returned
to the General Fund. Furthermore, to deposit power sales
receipts which are in excess of bondholder covenants in the
Power Development Fund requires an appropriation from the
Legislature.
Inflation Adjustments
HB 758 specifically provided for escalation of the whole-
sale power rate on the basis of inflation. HB 655 and HB 758
provided for escalation of repayment to the State to assure
that the dollars returned to the State would have the same
purchasing power as those invested originally in the power
projects.
Tiered Retail Power Rates
HB 758 provided that, as a condition of obtaining power
from Authority projects, utilities would be required to put
into place a tiered or inverted retail power rate. This
provision was not, however, contained in any of the other
legislation. We would observe that the Alaska Public
Utilities Commission, which has jurisdiction over the retail
rates of most utilities in the State, also operates under the
control of the Legislature. If the Legislature wishes to
implement such a policy, it could be done more directly
through the statutes it enacts with the APUC.
4-16
•
COMPARISON OF RATES UNDER AUTHORITY
RATE DIRECTIVES
We have calculated rates for four major projects presently
under construction under the rate directives provided by SB 25,
HB 655, HB 758, and HB 9 for the years 1985 and 1990. The results
of this work are shown on Exhibit 4-2 on the following page. In order
that this comparison could be made on a "apples and apples" basis,
it has been necessary to make certain simplifying assumptions.
These assumptions are summarized on Exhibit 4-3.
For the most part, the data shown on Exhibit 4-3 has been
obtained from the Authority's budget documents. We have, how-
ever, made one adjustment which relates to providing 10% coverage
on debt service. The subject of debt service coverage is
discussed in some detail in Section 6 of the report covering
Authority financing.
The rate comparisons have been developed on the basis of
four cases:
0 Case A -Individual rates for each of the four projects
on the basis that no other projects existed.
0 Case B -Rates for Solomon and Terror
0 Case c -Rates for Solomon, Swan, and Terror
0 Case D -Rates for Solomon, Swan, Terror, and Tyee
SB 25 Rates
SB 25 provided a postage stamp or uniform rate for all of the
Authority's projects. Under Case A the individual rate that would
be applicable to.each project has been calculated and can serve as
a basis of the impact of the uniform rate on the individual rates
for each of the projects. It will be noted that under Case A the
SB 25 and HB 9 rates are identical.
The remaining rates shown for SB 25 increase successively
under Cases B, C, and D as additional projects are added. The 1990
rate which would result from the provisions of the "Susitna Black-
mail Clause" is also shown on Exhibit 4-2 under "Susitna Rate 1990."
4-17
.C.QMEABISQN Qf BATES UNDER ALASKA EQHEB AUIHQBITY RATE IHRE!::II~ES
(cents per KWh)
SB 25 HB 655L256 HB 2 wL2 QiH~ HB !I wLgap
"Susitna "Susitna Based on Avg.
Rate" Rate" Generation
1!!65 1!!!!0 19!,!0 1!!65 1!!!!0 1!!65 19!!0 1265 1220 12!!0 1285 1!!!,!0
CASfi A
Solomon 3.10 4.34 12.93 7.37 9.80 3,10 4.34 3.10 4.34 12.93 2.36 3.31
Swan 17.93 15 .. 08 22.79 27.08 24.24 17.93 15.08 17.93 15.08 22. 79' 6,72 7.20
Terror 18.67 16 .. 18 19.48 26.28 24.40 18.66 16.18 18.66 16.18 19.48 11.79 12.07
Tyee 26.47 1.8.45 24.09 37.53 27.67 26.47 18 .• 45 26.47 18.45 24.09 6,05 6.45
""' CASE B I
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(X) Solomon 13.73 12 .. 84 17.63 7.37 9,80 10,91 12 .• 15 13.02 12.15 12.93 8.69 9.25
Terror 13.73 12 .. 84 17.63 26.28 24.40 1,5.03 13.,11 14.05 13.11 19.48 9.34 9.78
CASE c
Solomon 14.56 13 .. 32 18.76 7.37 9.80 10.58 11..82 12.70 11.82 12,93 8.60 8.99
Swan 14.56 13.32 18.76 27.08 24.24 20.02 16 .. 71 16.73 16.71 22.79 8.12 7.99
Terror 14.56 13.32 18.76 26.28 24.40 14,43 12 .. 60 14.64 12.60 19.48 8.52 9.40
CASE D
Solomon 16.45 14.35 19,83 7.37 9,80 10.64 11 .. 88 13.02 11.88 12.93 8.93 9.11
Swan 16.45 14.35 19.83 2'7.08 24.24 20.18 16 .. 84 18.38 16.84 22.79 . 8.26 8.12
Terror 16.45 14.35 19.83 26.28 24.40 14.56 12 •. 70 16.29 12.70 19.48 7.76 9.35
Tyee 16.45 14.35 19.83 37.53 27.67 2s .·as 18 .. 04 19.51 18.04 24.09 6.62 6.36
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SUMMARY OF ASSUMPTIONS FOR RATE COMPARISONS
PROJECT
Solomon Swan Terror Tyee
Date of Completion (FY) 1982 1983 1985 1984
Installed Capacity (KW) 12,oo·o 22,000 20,000 20,000
Average Annual Generation (MWh) 53,872 85,400 139,700 133,000
~ Capital Cost ( $000) I
~ Debt Financing 0 35,000 115,000 50,000
1.0 State Grants 53,000 58,000 88,000 62,000
Total 53,000 93,000 203,000 112,000
Proportional Debt Share Under HB9 ($000) 3,093 5,429 11,850 6,538
33-year Average Rate of Inflation 5% 5% 5% 5%
Annual Costs ( $000)
Operation and Maintenance
1985 1,270 1,028 990 1,320
1990 1,781 1,442 1,388 1,851
Debt Service
Actual 0 4,281 14,066 6,116
Coverage 0 428 1,407 612
Total 0 4,709 15,473 6,728
Projected Sales (MWh) t<j
1985 41,000 32,000 88,200 30,400 :><
0::
1990 41,000 40,800 104,200 46,500 H
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HB 655/758 Rates
The rates under HB 655 and 758 are identical in the first 10
years of project operation. If rates h~d been calculated for a
year in the second decade of projec~ life, they would have been
higher under EB 758 because of the escalation provisions of the
rate directives provided by that legislation (HB 758 escalates
the wholesale power rate gng the debt service by the appropriate
factor).
As will be noted, the rates do not vary for the individual·
projects under the four cases. This is because both of these
pieces of legislation provided for a project specific rate that
would not have been impacted by the level of costs of any other
project.
HB 9 Rates
HB 9 rates were calculated, on the basis of sales forecasts
contained in Exhibit 4-3, both with and without the effect of the cap
provisions provided by this legislation. We have also calculated a
1990 rate reflecting the provisions of "Susitna Blackmail Clause"
(see "Susitna Rate" in table). In addition, we have calculated
rates under HB 9 reflecting the effect of the cap provision based
on full utilization of average generation for both 1985 and 1990.
Looking first at 1985, it will be noted that the operation
of the cap provision results in increases in the rates for both
Solomon and Terror, but decreases for swan and Tyee. In 1990,
however, the cap has no effect. The reason for this is that by
1990, sales on the all of the projects except Solomon have in-
creased at a rate that exceeds the escalation rate assumed for
operation and maintenance expenses.
With respect to the "Susitna Blackmail Clause", in 1990, based
on sales projections, all of the projects would have higher rates
·if this provision becomes operational.
When the rates are calculated on the basis of average generation
or of full utilization of project output, the effect is rather drama-
tic. Under Cases B, C, and D, rates fall below 10 cents per kwh
for each of the projects in both 1985 and ~990. This highlights
4-20
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the importance of full utilization or a level of utilization that
approaches the capacity of hydroelectric projects as soon as pos-
sible after their completion.
EVALUATION OF THE AUTHORITY'S RATE STRUCTURE
As previously discussed, we have evaluated the Authority's
rate structure on the basis of four criteria:
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Efficiency in providing a stable flow of revenue
sufficient to cover costs over a relevant range of
variations in load
Consistency with conservation goals
Consistency with policy goals other than conservation
Equity in the distribution of costs
Equity in the distribution of benefits of State funding
The results of this evaluation are_discussed below.
Reyenue Stability
In developing any utility's rate structure, a major concern
must be the efficiency of rates in providing a stable flow of
revenue sufficient to cover costs over a relevant range of
variations in load. This is more commonly referred to as
"revenue stability".
The problem of revenue stability is of particular concern in
the structuring of rates primarily involving hydroelectric gene-
ration. First, almost all costs associated with hydroelectric
generation are fixed. That is, the annual revenue requirement
associated with a hydroelectric generaiing facility does not vary
in any significant amount on the basis of the number of kilowatt
hours generated. This, coupled with the fact that the level of
stream flows, and therefore the potential generation, is a func-
tion of the amount of rainfall or snowfall that occur during the
course of the year, provides a potentially serious revenue stabi-
lity problem. If the output of hydroelectric projects are fully
sold or committed and such sales or commitments are based on
4-21
average stream flow conditions there will be a revenue shortfall
during dry years.
There are a number of ways that this potential revenue
shortfall can be mitigated. The most effective might be to
establish rates on the basis of installed capacity, as opposed to
energy, and structure the charge such that purchasers pay on the
basis of entitlement to capacity at a fixed rate per kw (as
opposed to kwh). Although it would be possible to design a rate
to be charged on a per kwh basis which would cover the dry year
contingency,· a more effective approach is to deal with this poten-
tial problem contractually. This is the approach that the
Authority has used.
Our comments with respect to rate stability pertain both to
the HB 9 and SB 25 rate structures. In the setting of rates, it
is necessary to project both costs and the level of production
from a particular project, which is a function of the amount of
water that will be available in the case of hydroelectric
projects. If actual conditions vary from the projections and
assumptions, either a revenue shortfall or excess revenue might
result. The concern for revenue stability relates to the former.
The most volatile factor relating to revenue stability is the
amount of water available, which is beyond the control of the
Authority or any other rate setting body. As indicated above,
the Authority has chosen to deal with this problem contractually.
In the Authority's power sales contracts a mechanism is
provided for adjustment of rates from particular projects based on
the availability of water. It is our observation that this mecha-
nism will provide a vehicle to assure adequate revenues in dry
years. This would be true under either the HB 9 or the SB 25 rate
structures and is.the most efficient.way to deal with this problem.
Conservation Considerations
The primary conservation concern with respect to rates is
that rates not be subsidized to the point that cost effective
conservation programs are not feasible. In other words, whether
or not customers will undertake conservation depends on whether
or not that conservation will be cost effective. With full
knowledge, if the customer can save more in the electric bill
than he spends on the conservation feature, a rational choice
would be to implement the conservation feature. If rates are
subsidized, there is a bias against some conservation programs.
We have previously discussed initiation of a more concentrated
effort in the area of conservation, which would yield.value in
terms of the level of cost effectiveness for various conservation
programs. This information will serve as a benchmark against which
to measure whether or not it is prudent to subsidize electric rates
to a level that might preclude the implementation of conservation,
which would be in the best interest of the State and the utility's
ratepayers. Even lacking this data, however, the level of rates
that are projected for the several projects in which the Authority
is involved, as well as the level of rates paid by ratepayers even
after the effect of the Power Cost Assistance Program, is such that
this will probably not be a consideration.
The concern for consistency between rates and conservation ·is
one that is more directly applicable in the case of retail rates.
These are the rates that the customer pays and are therefore the
rates that influence the customer's decision.
Policy and Equity Considerations
Because of the fact that the Authority's rates are set
on the basis of the rate directives provided by the Legislature,
which are very specific with respect to the distribution of costs
and benefits, the Authority's rates are not only consistent with
policy, but are a vehicle for direct implementation of policy.
There is some difference in the distribution of costs and
benefits between the rate· structure provided under SB 25 and that
under HB 9. In the case of SB 25, a single rate would have been
established ·for all projects. In other words, the costs of all
projects would be totalled and the projected sales of those pro-
jects utilized to calculate a common or "postage-stamp" rate that
would be applicable for all sales. The effect of this would be an
A.-?1
equal distribution of the costs of projects, as well as the bene-
fits of State funding contributions to those projects, and to all
customers that would be served power generated from Authority .
projects.
HB 9 made a very significant change in this approach in that
it mandated that ~ach individual project would bear the annual
operation and maintenance costs associated with it as well as the
associated debt service. It did provide, however, that there
would be a limited leveling of debt service subject to a cap
whereby projects that had relatively high debt service costs
would receive some subsidation from those with relatively low
debt service costs. This reflects a modification of policy with
respect to the distribution of benefits of State funding.
ALTERNATIVES FOR LEGISLATIVE DIRECTIVES GOVERNING
THE AUTHORITY'S RATE STRUCTURE
As previously outlined, the Federal Government has, for the
most part, preempted State regulation of wholesale power rates
leaving to the states the regulation of retail rates for the sale
of electricity within their own boundaires. Therefore, Alaska is
somewhat unique in that the Authority is a State agency which
markets power at wholesale, but which is under the control of the
Legislature and Governor. Further, the State has invested substan-
tial sums in the development of power projects, most recently under
the Energy Program for Alaska.
Primarily for these reasons, the State's interest in the
Authority's wholesale rate structure goes beyond the conventional
concern that rates be established on a just and reasonable, or
cost basis. The State, has a vested interest in all phases of
power supply by reason of both its overall energy policy concerns
and its participation in power project financing.
Rate Structure and Rate Level
As previously discussed, it is important to draw a distinction
between rate structure and rate level. Rate level is governed by
the total revenue requirement of the utility. This is the amount
4-24
that must be raised, or in the case of regulated utilities the
amount that is allowed to be raised fro~ rates. Rate structure, on
the other hand, relates to distribution of the revenue requirement
between customer classes and individual customers within the same
customer class. These are important policy considerations that
must be addressed in the Authority's rate directives provide~ by
the Legislature.
Rate Structure Considerations
In the case of the Authority, rate structure relates to the
distribution of revenue requirement or costs between projects.
Given the Legislature's directive under HB 9 that each project
should bear its own operation and maintenance costs, the question
becomes one of how debt service, explicitly, and the benefits of
the State funding for project construction, implicitly, are distri-
buted.
Present Rate Structure Directives
We believe that the requirement that each project bear
its own operaton and maintenance cost is proper. This is
entirely consistent with the body of statutory directives
relating to rates at the federal and state level generally.
To do anything else would be a clear subsidy from one set of
ratepayers to another set of ratepayers.
With respect to the distribution of debt service and the
benefits of State funding, this is clearly a policy question.
From our review of legislation that has been both considered
and enacted, it is obvious that the Legislature has devoted a
great deal of time to this question.
Additional Rate Structure Considerations
We believe that the legislation that has been considered
and that which has been adopted in recent years has provided
an exploration of a wide range of alternatives with respect to
4-25
the structuring of rates. There are, however, two additional
areas that we believe should be considered.
T-he HB 9 wholesale power rate for each project is based
on energy. In other words, it is a rate per kwh of energy
delivered from a project. To put this in context, it must be
realized that there are three rather distinct "products" that
are produced from a hydroelectric generating facility:
0 Firm energy
0 Nonfirm energy
0 Capacity
The wholesale power rate is designed on the basis of firm
energy available from a project. HB 9 implicitly provides,
however, that the rate be applied to both firm and nonfirm
energy produced from a project. There is no provision in the
HB 9 rate for a capacity component or for a separate wholesale
capacity rate.
~n most years there ~ill be some amount of nonfirm or
secondary energy available from Authority projects. This is
energy that is in excess of that produced on a firm basis,
based on historic water conditions. Under HB 9 this energy
would have to be sold at the same rate as firm energy,
although it is generally recognized that nonfirm energy is not
the same quality of product as firm energy. This is the case
because it is only sold on an "as, if and when available
basis". In contrast, firm energy is, in effect, guaranteed to
be available.
Under the HB 9 rate it is implicitly assumed that capa-
city follows energy in the sense that all energy sold from a
project would be sold with the same capacity factor. Particu-
larly in the Railbelt, different utilities may have different
requirements for capacity and energy. In some cases there may
even be a requirement or a market for capacity alone, without
energy.
We believe that consideration should be given to pro-
viding a mechanism to allow for the sale of nonfirm or secon-
dary energy and, perhaps, even firm energy that is surplus to
4-26
the needs of all purchasers from a particular project. This
would be sold at a rate less than the wholesale power rate.
The market for this energy would most likely be fuel displace-
ment. That is, utilities with transmission access to a pro-
ject might purchase nonfirm energy, as it was available, to
dis91ace the!mal generation. It is not uncommon that such
transactions take place on some form of a "share of savings
basis". In some cases the savings are split on a 50/50 basis
between the buying and selling utilities; in other cases the
selling utility takes a larger percentage, as high as 80 to
90% of the fuel savings. The advantage of this approach would
be that additional revenues would be generated during times
when the full output of a particular project could not be
utilized by those utilities which had entered into power sales
contracts with the Authority. This additional revenue would
serve to reduce the level of the wholesale power rate paid by
firm energy purchasers.
Likewise, we believe that consideration should be given
to providing a mechanism to establish a capacity rate. such a
rate could be developed in one of several ways. For example,
the basic wholesale power rate could be structured with sep-
arate capacity and energy components. Under this rate form,
utilities would pay the Authority based on a combination of
the maximum rate of delivery or capacity they utilized and the
total amount of energy that they would take. Alternatively, a
capacity rate could be developed that would be utilized for
the sale of capacity only. That is, the wholesale power rate
would continue to operate as envisioned by HB 9, but the
capacity rate would be applied for transactions involving only
capacity. For exa.mple, any surplus capacity, above that which
would be sold under the wholesale power rate with energy,
would be sold at the capacity rate.
Rate Level Considerations
Because the Authority sets its own rates without review by any
regulatory body and because it plans to undertake a significant
4-27
amount of revenue bond financing, it is important that it be pro-
vided with definitive directives as to the level of its rates.
Present Rate Level Directives
The Legislature has provided directives with respect to
the level of the Authority's rates in all of the statutes
under which the Authority has operated. This is discussed
under the heading, "Evolution of Authority Wholesale Power
Rates", earlier in this section of the report. The rate
directives provided under HB 9 specifically set forth.the
components of the Authority's revenue requirment to be
recovered through its wholesale power rates.
With respect to the Authority's total revenue required
for all projects, these are:
0 Operation and maintenance expenses
0 Inspection costs
0 Debt service on outstanding State bonds and loans.
The present statutory directives with respect to the
level of rates, therefore, provide the Authority with revenues
sufficient to meet the "ordinary" annual costs of all of its
projects. There is, however, no explicit provision for set-
ting the revenue requirement .at a level sufficient to cover
"extraordinary" costs, nor is there an explicit provision for
the provision of any coverage on debt service.
Additional Revenue Requirement Considerations
A utility generally will include in its revenue require-
ments certain components beyond "ordinary" annual costs.
These include:
0
0
The balance of the Authority's administrative and
general expenses which are not capitalized
Depreciation
4-28
0
0
An amount to provide funding for certain reserves
An amount to provide some level of debt service
coverage required in excess of the amounts included
for depreciation
As the Au~hority undertakes operation of completed pro-
jects, either with its own personnel or under contract with
local utilities, some portion of its administrative and
general costs will be related to these projects. This will be
different than in.the past when its entire effort was devoted
to planning and project development. As this evolves, it may
be found appropriate to include these costs in rates. A broad
definition of what comprises operation and maintenance costs
would allow such a policy without additional legislation.
Under conventional utility accounting practices,
interest on outstanding debt is considered an expense. The
recovery of the capital co~t of a project is generally
accomplished, in the case of publicly owned utilities,
through the inclusion of a depreciation cost component in
the revenue requirement. However, this is a "non-cash"
expense and it "flows through" to the balance available for
debt service. Therefore, it is an amount that is included in
the revenue requirement that is available for the principal
component of debt service and debt service coverage. The
latter is discussed below.
Because of the Authority's intended utilization of reve-
nue bond financing with its attendant requirement for the
production of accounting statements on an enterprise basis, a
depreciation cost component will probably have to be included
in the revenue requirement, or at least displayed in financial
statements •.. It is emphasize_d, however, that this will not
impact the level of rates in that the principal component of
debt service must be recovered and there will have to be some
debt service coverage included in the revenue requirement.
It is common for utilities to include in their revenue
requirements funding for the creation and maintenance of cer-
tain reserve accounts. In the case of Authority, some of
these requirements have been met through legislative appro-
priation. However, one reserve fund that is directly related
A nn
to individual projects is that for renewals and replacements.
In the ordinary operation of a project from year to year,
certain pieces of equipment and apparatus require major main-
tenance or even replacement before the project reaches the end
of its useful life. However, these expenditures do not neces-
sarily flow smoothly from year to year. Creation of a renewal
and replacement fund assures the availability of adequate
funds to meet these requirements as they occur. If this fund
is provided from the revenues of individual projects, then the
costs are born by the beneficiaries of those projects.
We believe that a broad interpretation of the operation
and maintenance expense category would allow the inclusion of
an amount, each year, to maintain a renewal and replacement
fund. Our experience indicates that utilities with substan-
tial hydroelectric generation have utilized a formula that is
based on providing 1/20 of the balances in the capital
accounts covering equipment (FERC accounts 333-turbine genera-
tor, 330-accessory electrical equipment, 335-miscellaneous
power equipment, and 353-electrical station equipment).
If such a practice were adopted, the amounts in the
renewal and replacement fund would be restricted for use in
repair and replacement expenditures above normal maintenance
costs related to the particular project for which the fund is
established. The Authority may find, however, that all of the
projects would benefit if it would pool the renewal and
replacement funds to assure that adequate funds were available
in the early years. A separate accounting could be kept to
maintain the balances of the individual projects in the pooled
fund.
We have previously discussed the subject of debt
service coverage and additional discussion is provided in
Section 5. All utilities that utilize revenue bond
financing covenant to provide some amount of revenue above the
absolute amount required for debt service. As is discussed
elsewhere, there is every indication that this will be
required for the Authority and therefore it can be expected
that the revenue requirement will have to reflect this.
4-30
In discussions with Authority staff and consultants,
the opinion has been expressed that the language of HB 9, with
respect to debt service, would allow such a practice. Argu-
ably however, it might be appropriate for the Legislature to
explicitly set forth the Authority's responsibility to provide
debt service coverage.
POWER SALES CONTRACTS
Earlier in this section and elsewhere in this report we have
made reference to, or discussed, power sales contracts. we have
had the opportunity to review both those power sales contracts that
have been executed and drafts of power sales contracts that are
currently being negotiated. With respect to the latter, we have
provided detailed comments to the Authority's Counsel on the
latest draft. A copy of these has been sent to the Study Manager.
An important issue is the timing of execution of power sales
co~tracts. Almost without exception, power sales contracts
covering projects in the lower 48 states are executed before any
financing is undertaken. Generally, this would coincide with the
determination of project feasibility and the initiation of project
design.
It is our observation that there is reluctance on the part of
utilities to execute power sales contracts for several reasons.
Uncertainty as to what the cost of power from the project will be,
both initially and over the long run, is one of their main con-
cerns. The concern for the initial cost of power relates, at least
in part, _to uncertainty as to the total amount the Legislature will
appropriate for the particular project. Over the longer run, there
is concern that projects subsequently approved might increase power
. . _ _.
costs because of the debt service provisions of HB 9.
As a practical matter, power sales contracts will p_robably
have to be executed before the Authority could undertake any long
term financing utilizing revenue bonds. However, the Legislature
may wish to consider the alternative of requiring power sales
contracts to be in place before any significant State appropria-
tions are made for design or construction of a project.
4-31
These subjects are discussed elsewhere in the report, but are
set out separately here to assure that the importance of this issue
is highlighted.
4-32
APPENDIX 4-A
1982 Proposed Changes
In Rate Statutes
Early in 1982, two bills to amend SB 25 were introduced.
HB 655 was introduced in January at the request of the Governor.
In March, the Resources Committee offered a substitute bill (CSHB
758). Both contained language which would have altered wholesale
power rate structure in Alaska.
HB 655 proposed to change the statewide wholesale power
rate, provide an adjustment mechanism when miscalculations were
discovered, create a new fund for the Authority, and utilize an
alternative formula for determining the return to the State on
its investment.
Under HB 655 the single statewide wholesale power rate would
have been replaced and each project would have had its own rate.
The Authority would have established, by regulation, a method for
applying a wholesaie power rate to various types of power projects.
By regulation, the Authority would have also been required to
establish a procedure for ·the adjustment of individual wholesale
power rates to compensate for overestimates or underestimates in a
previous year of program receipts or in the return due to the State
from its investment in the power project.
Except for these regulated adjustments, the wholesale power
rate would have been computed annually and set to provide receipts
sufficient to pay operation, maintenance, and equipment replacement
costs; including any repayments for loans from the Power Project
Emergency Maintenance Fund (which this bill would have established
in the Authority to bridge gaps when other appropriations were not
available or were insufficient to cover these non-capital costs).
Debt service on bonds issued and safety inspection and investiga-
tive costs would also have been components of the calculation.
Furthermore, this bill would have removed the so-called "Susitna
Blackmail Clause" entirely. It proposed a method wh~reby the
State would have been repaid the entire initial investment in equal
installments through yearly rate increases over a 33 1/3 year
4-33
period with each period's principal adjusted for inflation. This
procedure would have resulted in the state being repaid its invest-
ment in dollars of equal purchasing power.
For the first,year in ~hich a wholesale power rate would have
been in effect, the Authority would have determined the amount to
be returned to the state by multiplying the State's investment in
the power project by a factor of 0.03. For each subsequent year,
the amount to be returned to the State would have been escalated by
a factor of 1.0 plus the rate of inflation (calculated in the year
the wholesale power rate was initially established and equal to the
average of the preceding 33-year's rate of inflation based on the
Federal Consumer Price Index). Every ten years the Authority would
have recalculated the applicable escalation rate (for the 33-year
period preceding the recalculation) and would have used it for the
next lO~year period.
After 33 1/3 years, the amount to be returned to the State
would have been zero,_ unless other State investments in that parti-
cular power project were made after the wholesale power rate was
initially established. In that case, the additional return due to
the State would have been determined separately in the manner
described above. This amount would have been treated as an addi-
tional debt service cost for the project.
CSHB 758 (HB 758) concentrated its rate reform on three major
areas: rate structures; the relationship-between, and procedures
for, the Authority and the APUC; and the method by which the return
to the State would have been calculated.
Like HB 655, HB 758 would have required that a separate whole-
sale power rate be established for each,power project~.Both bills
included the same components for calculating the wholesale power
rate (including loans from the Power Project Emergency Maintenance
Fund which would have been retained), except where the return to
the State was concerned.
One provision which set HB 758 apart was that it would have
provided for a consumer rate structure consisting of at least three
rates. The utility would have designated the lowest rate as the
~equity rate", and that would be the rate charged for the first 250
kilowatt hours of power used during a monthly billing period. In
addition, the utility would have specified successively higher
ranges of power usage to which successively higher charges would ,
have applied. This would have provided what is commonly referred
to as an "inverted" or "tiered" rate at the retail level.
This bill also would have changed the relationship between the
individual utilities, the Authority, and the APUC. For example,
utilities buying power from the Authority would have had to agree
to incorporate tiered rate structures into their retail pricing
schemes. In addition, before an affected utility could establish
or amend their rate structure under the new requirements of this
bill, the APUC would'have had to conduct a public hearing within
the utility's service area to explain the proposed action and its
effect on rates. e
Even though enactment of this bill would have complicated the
working relationships between the parties involved, nothing in HB 758
would have affected the authority of the APUC under existing statutes
(AS 42.05.361-42.05.441).
The third major area which this legislation would have dealt
with was the method and timing of repayment to the State of its
capital investment in power projects under the Energy Program.
Like HB 655, this bill would have deleted the "Susitna Blackmail
Clause" and provided a repayment schedule for money contributed by
the State. However, under this proposal, the repayment period
would have been 33 1/3 years or a period equal to 3/4 of the life
of the project (as determined by the Authority), whichever was
less. In other words, the typical thermal generating facility with
a_30 tq _35 year .useful life would have repaid the State's invest-
ment over 22 1/2 to 26 1/4 years, while a hydro facility would have
been allowed a maximum of 33 1/3 years.
Also, HB 758 would have calculated the inflation rate differ-
ently, and applied it to more items than HB 655. For the first
year in which a wholesale power rate was to have been in effect,
~he Authority would have determined the amount to be returned to
the State by dividing the State's investment in the power project
by the appropriate repayment period. This calculation would have
provided an equal payment stream to the State, but the first paY=
~ would not have been adjusted for inflation.
Initially, the inflation rate would have been calculated as
the 33-year average of the Federal Consumer Price Index. This
escalation factor (plus 1.0) would have been used in payback years
two through nine and it would ·have been multiplied by the amount
determined in the preceding year to establish that period's return
to the State. Every ten years, the inflation rate would have been
recalculated, and it is in this calculation that the two bills
would have differed. HB 755 called for the Authority to calculate
the average rate of inflation for the preceding 33-year snQ 10-year
periods and to use whichever was less (plus 1.0) as the escalation
factor (HB 655 would have used only the 33-year average). There-
after, new escalation factors would have been used to preserve the
State's repayment in constant dollars. This process would have
continued until the final installment was paid, at which time the
return due to the State would have been zero. (Additional State
investment repayments due for funding received after the original
wholesale power rate was established would have been treated the
same as in HB 655.)
As described above, this bill would have directed the
Authority to consider inflation over two different time horizons,
near and long term, and to use the lesser of the two to ensure that
the value, in terms of "purchasing power" of the State's capital
outlay was preserved when being repaid over an extended period.
(Note that the effect of inflation on cash flows during construc-
tion and up to completion was not accounted for in this formula
because the wholesale power rate and the amount due the State
were not calculated until the year that the project went on line.)
This bill also attempted to compensate for inflation's effect
on the wholesale power rate over time. Specifically, "Every 10
years after the initial establishment of a wholesale power rate,
the Authority shall calculate the average rate of inflation for the
preceding 33-year period and increase the wholesale power rate by a
percentage equal to the increase in the average rate of inflation
4-36
for the preceding 33 years or the preceding 10 years, whichever is
less." (section 44.83.398(f))
Both HB 655 and HB 758, like S.B 25, would have allowed the
Legislature to annul or change the wholesale power rate by law.
SECTION 5
REVIEW AND ASSESSMENT OF
STATE FUNDING OF POWER PROJECTS
INTRODUCTION
The State of Alaska's direct participation in the funding of
the costs of construction of power projects is not only unique
among other states but has been tne key to electrification of
bush areas and the construction of hydro and other projects that
will enhance service to the more populated areas of the State.
State funding has been undertaken on a project-by-project basis,
based on the availability of funds and project cost
considerations.
Legislative appropriations for power project development
have been made under several programs involving both the
Authority and other State agencies. The major programs under
which appropriations have been made include:
0
0
0
Alask~ Power Authority
Power Development Fund
Power Project Loan Fund
Rural Electrification Revolving Loan Fund
Legislative Grants for Power Development Projects
Department of Administration
Electric Power Grants
Department of Community and Regional Affairs
Legislative Grants for Bush Village
Electrification
These programs are reviewed in Section 2 of the report. Be-
cause of the relative magnitude of the various programs, only the
Power Development Fund is discussed further in this section.
ENERGY PROGRAM FOR ALASKA
Funding for projects included in the Energy Program for
Alaska {Energy Program) has, since 1981, been provided through
appropriations by the Legislature to the Power Development Fund.
These appropriations provide fund~ for construction of projects
identified through reconnaissance and feasibility studies and
approved by the Legislature. Funds provided by the Legislature
as loans, prior to iniation of the Energy Program, have been
replaced by grants for those project involved in the Energy
Program.
At the time the Energy Program was enacted, it was
envisioned that the State might undertake total funding of power
projects from oil and gas revenues. With the stabilization of
oil prices and the resulting reduction in State revenue
projections, this approach is no longer considered feasible.
Therefore, projects included in the Energy Program, as a
practical matter, will have to be funded from a combination of
State revenue, under the Energy Program, and the proceeds of
interim financing which will be replaced with long-term debt upon
completion of the projects.
PROPOSED ENERGY RESOURCE FUND
After the 1982 session of the Legislature, the House
Research Agency was requested to develop an approach involving a
dedicated Energy Fund as an alternative to present State funding
practices. A copy of their October 4, 1982 response to this
request is included as Appe_ndix 5-A. The major elements of the
Energy Fund, as proposed, are summarized below.
0 The -Energy Fund will receive at least 25 percent of the
State's royalty revenues for a fifteen year period,
beginning in FY 86, the earliest full fiscal year in
which the program would be in effect. This would
amount to over $3.1 billion {1982 dollars) or
approximately $7,856 per current resident. At the ~nd
of the fifteen-year period, the contribution rate into
the Fund would be cut in half, in order to meet the
objective of providing funds to keep pace only with
population growth. The_contribution rate and the
5-2
0
0
0
0
0
0
0
duration of the initial period of full funding are
subject to revision as revenue forecasts and cost
estimates for the major projects change.
The Fund would be housed in the Department of Commerce
and Economic Development and administered by a six-
member board. The Commissioner of Revenue would be
responsible for investing the Fund.
As deposits and interest earnings flow into the Fund,
they would be allocated and would accrue to the
accounts of energy management areas, on the basis of
each area's population (computed for Municipal Revenue
Sharing} for the previous year. The per capita
distribution of funds would be adjusted for
construction cost differentials in the different areas
of the State. No area would be allowed to accrue its
share of the Fund more quickly than another area.
An energy management area could draw upon its account
to construct an energy facility which would reduce the
area's dependence on fossil fuels imported from outside
the area .s..n.Q which had been approved by both the Energy
Fund board of trustees and the area's voters.
Local service area boards would operate these
facilities, or could contract with the Alaska Power
Authority for these services. The Alaska Power
Authority would retain responsibility for
reconnaissance and feasibility studies and project
construction.
In adition to financing construction of energy
projects, Energy Fund entitlements could also be used
to meet debt service on bonds issued by the area.
First and second class boroughs would automatically
become energy management areas, and their governments
would become energy management boards. In areas
outside these boroughs, the Commissioner of Community
and Regional Affairs-would designate area boundaries
and elections would be held for each area's board.
Two or more areas may jointly propose a project to the
Fund's board for approval. For projects involving
significant economies of scale, the board would be able
to mandate a joint project involving two or more areas.
Discussion of Proposed Energy Resource Fund
The House Research Agency response identifies and
discusses a number of issues relating to the proposal (Appendix 5-
A, pages 3 -9). It is suggested that this material be reviewed
since it is not repeated here. Our discussion of the proposal is
intended to supplement their work.
The decision of the State to directly participate in the
funding of the costs of construction of power projects reflected a
very basic and certainly a major policy decision. The proposal
to establish a dedicated fund with earmarked revenues is
likewise a major policy decision.
Clearly, th~re are public•policy arguments against both a
commitment of State funds to power plant development and the
taking of the "next step", creation of a dedicated fund with
earmarked revenues. We assume that these arguments will be
presented and duly considered. Our discussion of the Proposal
takes the decision for State participation in the funding of power
projects as a given and focuses on the advantages and disadvaniages
of the Proposal for a dedicated energy fund with respect to its
impact on the original State funding decision.
The Proposal embodies the creation of a dedicated energy fund,
earmarking of revenues, and establishment of a multitiered struc-
ture to administer the dedicated fund, a methodology for alloca-
tion of funds, and a procedure for approval of projects in which
funds would be invested. In effect, it provides a "stand alone
system" for power projects that utilize State funding. The
following comments are directed to these major features of the
Proposal.
Dedicated Fund
The providing of a dedicated fund with earmarked revenues that
would accrue balances over time would have some distinct advantages
in the financing of power projects. One of the problems with the
current method of State funding is the requirement that
appropriations be made on an annual basis. This introduces
uncertainty as to the continuation of appropriations and the
ultimate total level of State participation in a particular
project. A dedicated fund, assuming it was structured in a way
that removed the prohibition against multiyear commitments, would
provide for the allocation of a certain amount of money to a
particular project which could be drawn down on the basis of that
project's cash flow.
The advantages of this would be that any required debt
financing could be scheduled with more certainty and that financing
could be made on the basis of the committed State funds which would
enhance marketability. Equally as important, with a known level of
State funding for a particular project the cost of power from that
project could more accurately be estimated. This would facilitate
execution of power sales contracts.
We have no basis for comment on the adequacy of the level of
the fund. It is noted that the Railbelt share would be
approximately 50% of the requirements for Susitna financing through
1998 (1982 dollars). If the level of funding provided by the
Proposal was determined to be inadequate at some future time, the
State could supplement the amount either by increasing the
percentage of royalty revenue earmarked to the fund, or by
appropriations from other sources of revenue.
Administrative Structure
The Proposal envisions a statewide governing board as well as
local boards for the individual energy management areas. In the
case of first and second class boroughs, the existing governmen.t
would serve as the energy management board.
The House Research Agency's analysis recognized this, both
with respect to the exclusion of the executive and legislative
branches and the participation of Authority in projects that might
be constructed from the Energy Fund. Consideration should be given
to whether or not the local input and independent control functions
of the structure in the Proposal could be achieved within the
existing governmental structure of the State. This might be
accomplished through requirements for concurrence by local
governmental entities with proposed projects and even a requirement
that an advisory election be held within the service area of the
project.
This alternative would leave with the Legislature and Governor
the final decision on the expenditure of State funds for power
projects. The Authority, then, would continue its work on recon-
naissance and feasibility studies as well as the financing and
construction of projects that were approved. The change here would
be whatever requirements were imposed with respect to expressions
. of approval of projects from the areas that they would ~erve.
One other point, in this regard, is that the Proposal ignores
the existence of utilities that serve the various areas of the
State. If the Proposal is pursued, there will have to be some
consideration given to how the utilities who will have to
distribute power from projects constructed from the fund will fit
into the program.
Allocation of Funds
The Proposal anticipates the allocation of funds to the
several energy management areas would be made on the basis of
population. Unfortunately, it·is easier to criticize this aspect
of the Proposal than it is to propose alternatives.
The House Research Agency has pointed out potential problems
with this method of allocation. We agree that those they cite are,
in fact, concerns. If a decision were made to stay within the
existing administrative structure, consideration should also be
given to not initially specifying how funds will be allocated. As
time passes and the actual need for additional generating capacity
becomes clearer and as projects are proposed to meet these needs
more enlightened decisions can be made with respect to the most
approp.riate v1ay to make the allocations from the fund. It might be
found that continuation of the Power Cost Assistance Program in
some more remote areas of the State would be a more efficient way
to provide benefits to those areas than would additional capital
investments from State sources of revenue. This is not to sug-
gest that if after due consideration with full recognition of the
shortcomings of an allocation ori the basis of population that a
decision might be made to proceed on this basis.
5-6
One other point with respect to the allocation of funds
relates to their utilization to meet annual debt service costs.
Since the .greatest portion of debt service in early years is the
interest component, the application of these funds f~r this
purpose would not constitute an investment in power production
facilities.
OTHER ALTERNATIVES
In discussions relating to State funding it is clear that a
number of alterriatives have been considered. It has been our
observation that the benefits of State participation in power
project financing would be enhanced if the level of participation
in a particular project could be determined other than on an
annual basis. This would facilitate development of financial
plans and, more importantly, facilitate execution of power sales
contracts at an earlier date. One alternative that would accom-
plish this would be to initiate multiyear appropriations.
Pouch Y, State: Capitol
Juntau, Alaska 99811
(907) 465-3991
ALASKA STATE LEGISLATURE
HQUSE OF REPRESENTATIVES
RESEARCH AGENCY
APPENDIX 5-A
October 4, 1982
MEMORANDUH
TO: Representative Eric Sutcliffe
FROH: Anne De~and Jack Kreinhede~
Research Staff {;JI \.
"RE: Proposed Energy Resourc~ Fund --Revised Draft
Research Request 82-156
You asked that the Agency develop your concept for an energy resource
fund into a workable program which 1'/ould finance energy projects on a·
statewide basis. You indicated that the fund should meet the following
criteria:
it should provide equity, measured by expenditures per capita, in.·
State funding for energy projects;
it should be sufficiently large to accommodate the State 1 S expected
contribution to all currently planned hydroelectric projects; and
it should only finance projects l'lhich have received the approval of
voters in the area served.
We have taken your initial framework and expanded it into the suggested
legislation found in Attachments A and B. \o/ithin the body of this
memorandum, 1ve briefly outline the program and discuss potential issues
which surround such a fund. During the course of our work, it became
apparent that there are a number of factors on which 1-1e require further
guidance fran you; these are discussed in the text .and in footnotes to
the 1 e g i s 1 a t ion •
To campi le the suggested language, we have dra1vn from existing statutes
regarding the Permanent Fund and the Alaska Coastal t1anagement Program.
In addition, the following individuals reviewed, at some stage, a
draft of this proposed legislation: McKie Campbell, aide to Senator
Gilman, regarding local government considerations; Milt Barker, Legis-
lative Finance, on financial issues; Ron Lorenson, Deputy Attorney
General, regarding the general concept and language; and Dick Bradley,
.·
Representative Sutcliffe
October 4, 1982
Page 2
Legal Services, also concerning language. Their comments have been in-
corporated in the legislation or noted in the text. As you indicate
where changes are needed, we will work with Mr. Bradley in drafting
revised language.
Outline of the Proposed Energy Fund
The Energy Fund wi 11 receive at 1 east 25 percent of the State 1 s
royalty revenues for a fifteen year period, beginning in FY 86, the
earliest full fiscal year.in which the program would be in effect.
This would amount to over $3.1 billion (1982 dollars)! or approxi-
mately $7,856 per current resident. At the end of the fifteen-
year period, the contribution rate into the Fund would be cut in
half, in order to meet your objective of providing funds to keep
pace only with population growth. The contribution rate and the
duration of the initial period of full funding are subject to
revision as revenue forecasts and cost estimates for the major
projects change.2
The Fund would be housed in the Department of Commerce and Economic
Development and administered by a six-member board. The Commission-
er of Revenue would be responsible for investing the Fund.
As deposits and interest earnings flow into the Fund, they would
be allocated and waul d accrue to the accounts .of energy management
areas, on the basis of each area 1 s population (computed for Municipal
Revenue Sharing) for the previous year. The per capita di stri but ion
of funds would be adjusted for construction cost differentials in
the different areas of the state. No area would be allowed to
accrue its share of the Fund more quickly than another area.
An energy management area could draw upon its account to construct
an energy faci 1 i ty which waul d reduce the area 1 s dependence on fos-
sil fuels imported from outside the area and which had been approved
by both the Energy Fund board of trustees and the area 1 s voters.
lwhile this approach only approximately achieves your goal of depositing
$7,500 per person over a period of time, it is simpler to legislate and
a dm i n i s t e r •
2current oil and gas royalty projections terminate in 1998, which
waul d be only thirteen years after the start of this program. For
the thirteen-year period 1986 through 1998, 25 percent of expected
oil and gas royalties total $3,142.28 million {1982 dollars).
Representative Sutcliffe
Ocotober 4, 1982
Page 3
Local service area boards would operate these facilities, or could
contract with the Alaska Power Aut hori ty3 for these services. The
Alaska Power Authorlty would retain responsibility for reconnaissance
and feasibility studies and project construction.
·. In addition to financing construction of energy projects, Energy
Fund entitlements could also be used to meet debt service on bonds
issued by the area.
First and second class boroughs would automatically become energy
management areas, and their governments would become energy manage-
ment boards. In areas outside these boroughs, the Commissioner of
Community and Regional Affairs would designate area boundaries and
elections would be held for each area's board.
Two or more areas may joint 1 y propose a project to the Fund's
board for approval. For projects involving significant economies
of scale, the board would be able to mandate a joint project involv-
ing two or more areas.
Issues
This approach to financing energy projects raises a number of philo-
sophical and practical questions. Each of the.se questions is briefly
discussed bel ow.
Why do energy investments warrant the commitment associated with
dedicated revenues when other important State functions, such as ed-
u cat i on , do n ot?
This is probably the most important philosophical issue surrounding
this program, or any program calling for dedicated funds.
While energy investments may be an important State activity, it is
not clear why such investments should not be forced to compete with
other demands on the State treasury, particularly when greatly reduced
revenues are projected for the future. As Attachment C shows, unre-
stricted general fund revenues in 1998 may only be approximately 27
percent of current revenues, in real terms. Under those circumstances,
3vour original outline did not indicate how the activities of the
Fund related to those of the Alaska Power Authority. Later in this
memorandum, we discuss a number of options for different levels of
APA involvement.
Representative Sutcliffe
October 4, 1982
Page· 4
the State•s priori.ties may be expected to change, so that in the future
energy may or may not seem as such an important investment as it does
today.
Why should money for energy investments be provided on a per capita
basis, with no consideration of the need for an energy project, and
no adjustment for differences in project scale~
From an apolitical public policy perspective, it is not clear why ener-
gy projects should be funded on a per capita basis. Not all areas of
the state may be able to absorb the funds allocated to them, particu-
larly in western and northern Alaska where alternatives to diesel
generation are limited. On the other hand, projects in rural areas
will tend to be smaller and have higher costs per unit of energy pro-
duced. Although this revised draft incorporates an adjustment in
the distribution of funds to account for construction cost differences
in various areas of the state, such an index would not reflect the
higher relative costs of smaller projects.
The construction cost adjustment included in this revised draft would
increase the per capita amounts for high cost areas of the state and
reduce the per capita amounts for areas with relatively low construc-
tion costs. In practice, this would mean more funds (on a per capita
basis) for rural areas and less for urban areas, thus raising the
potential for divisiveness on this issue.
Is it wise to exclude both the Executive and Legislative branches
from any role in the distribution and use of this amount of money?
Neither the Executive nor Legislative Branch is involved
process of spending these funds. This could be viewed as a
or a drawback of the program depending on one•s perspective
certainly an issue which may be raised.
in the
benefit
and is
Should local governments be formed in rural· areas to· administer
this program?
You suggested that this program be administered by local service areas.
The creation of yet another set of boundaries in rural areas for the
delivery of services raises the question of whether it is time to estab-
lish more local regional governments. Some individuals will resent
Representative Sutcliffe
October 4, 1982
Page 5
the imposition of ·an Energy Management Area structure in order to re-
ceive their per capita grants, while others might argue that fully
funct iona1 regional governments should be formed to administer these
grant monies.
How should feasibility studies be funded?
In your outline, you indicated that Fund money was to be used for the
design and construction of projects which already have been determined
feasible. Consequently, we assumed that you did not want fund money
to be used for feasibility studies, and have included that provision
in the proposed legislation.
Given the high cost of some feasibility studies, it seems that some
areas could easily consume large amounts in the study stage without
ever benefiting from new energy sources.
There are at least three alternative ways that areas could secure
funding for feasibility analyses: local revenues could be used; spe-
cial State appropriations could be sought,-a means of involving the
Executive and Legislature; or, the Energy Fund board could distribute
grant money, which had been appropriated to the Fund in a lump sum, to
local areas for the purpose of analyzing project feasibility.
What is the desired relationship bet\-1een the Fund and the Alaska
Power Aut ho ri ty?
In your outline, there was no indication of how the relationship be-
tween the Energy Fund and the Alaska Power Authority was to be struc-
tured. In the original draft of August 9, we established a separate
entity where the APA • s role wou 1 d be limited to its contractu a 1 re-
lations hips vd th energy management areas regarding the camp let ion of
feasibility studies, and the design, construction and operation of
facilities.
In this revised draft, the APA would reta:in responsibility for recon-
naissance and feasibility studies and project construction. The area
boards \'IOuld be responsible for working with the public and the local
utilities to ensure that their concerns were reflected in the project
evaluation and selection process. Based on the reconnaissance studies,
the area board would recommend the project or projects for which feasi-
bility studies v10uld be conducted by the APA. Those projects which
Rep resent at i ve Sutc 1 i ffe
October 4, 1982
Page 6
are feasible would then be recommended by the area board to the state
board, placed on the ballot, and constructed by the APA if approved
by the voters.
Currently, projects constructed by the APA are subjected to .a two-step
approval process. The Division of Budget and Management in the Gover-
nor's Office approves feasibility plans and financial plans prior to
submission to the legislature. Under this revised draft, we have
retained the review of reconnaissance and feasibility studies by the
Division of Budget and Management, but have not included a requirement
for legislative approval in accordance with our interpretation of your
outline. As mentioned earlier, legislative approval is one of the
major issues to be considered.
If the Energy Fund is established apart from the APA, and assuming that
the money contributed to the Energy Fund represents the bulk of the
State's commitment to energy project financing for the foreseeable
future, the APA's role in shaping State energy policy would be greatly
reduced. Even if the Fund were incorporated into APA, p rovi si ons for
equity in per capita financing and voter approval would constrain the
policy latitude of the Authority.
There are at least four ways in which the APA could be affiliated with
the Energy Fund:
1) areas could be required to use the· APA for feasibility, design,
construction and management services, for projects initiated within
the area (as in this revised draft).
2) the APA could be made responsible for projects of a certain type
and size.
3) the APA could recommend projects to the area board and present
them to the area board and the fund board. Essentially, the APA
I'IOuld be staff to each board. It would then have the responsi-
bility for designing, constructing and maintaining the project.
4). the .APA. could recommend, own and operate these facilities. The
activities of the APA would only be subject to voter approval in
the area served, as no separate legislation 1vould be required for
these faciliti-es. The fund board would take the place of the
Division of Budget and Management.
These alternatives would permit the APA varying degrees of influence
over the selection and construction of energy projects.
Representative Sutc 1 i ffe
October 4, 1982
Page 7
Who owns the energy projects financed by the Fund?
In the suggested legislation, we have assumed that each energy manage-
ment area will own the facilities it builds. This seems appropriate,
particularly if the area were issuing bonds for the project. An alter-
native to this approach is State ownership and operation, through the
APA or the Department of Transportation and Public Facilities.
How should the economic feasibility of projects be determined?
We are assuming that these funds will be provided as grants to local
areas, and that no return on equity or interest would be repaidto the
State. Consequently, it seems that the only criteria for economic
feasibility is that local rates cover the costs of maintaining and
operating the facilities. Under the proposed legislation, Fund monies
may not be used to pay maintenance and operating costs.
Will this financing plan be adequate to meet the needs, both in
.total amounts and timing of revenues, of large-scale hydroelectric
projects, in particular--Susitna?
Table I, below, shows the: 1) amount of money which would be deposited
into the Energy Fund, assuming 25 percent of current Department of
Revenue royalty projections; 2) share which would be received by
energy management areas throughout the Railbelt; and 3) estimates
of the financing requirements of Susitna construction.
Representative Sutcliffe
August 9, 1982
Page 9
Even if the Fund-board forced the Railbe1t to jointly propose the
Susitna project, Anchorage residents could vote down such a proposal.
Similar factors may also affect Fairbanks.
How are the activities of energy management boards in the unorgan-
ized borough regulated to insure proper use of funds, etc.
If the program is established apart from the APA, it would. seem desir-
able to institute some form of controls over the local boards, to
insure the proper use of funds, etc., and avoid the abuses experienced
on some Region a 1 Education Attendance Area boards. At this point,
this program only requires financial accountability through annual
audits.
i~hat about those areas where there are no feasible alternatives
to imported fuels for either electricity or space heat and which
have exhausted their conservation possibilities--would they be able
to subsidize diesel imports?
The proposed program does not provide for an area which can generate
no approvable projects. If exceptions are to be made, some wording
of the constitutional amendment probably has to be changed. The program
also does not provide for an area which is not interested in submitting
projects; money would simply accrue to its account until such time as
it was interested in making energy investments.
After you have had a chance to review this memorandum and the attach-
ments, please let us discuss what changes you would like to see in the
proposed legislation.
AHD/JK/sj
cc: Representative Don Clocksin
Attachment A:
Attachment B:
Attachment C:
Proposed Wording for the Canst itut ion a 1 Amendment
Proposed Wording for Necessary Legislation
Projected Royalties and Energy Fund Deposits
-raD le l
Estimates of Contributions to the Energy Fund and Unrestricted
Based on June 1982 De~a rtment of Revenue Royalty Projections
{ 111 ions of 1982 Dollars)
Petro Prod. Sub-Total Est. Total
Real O&G Rea I O&G Less Contribution Unres ri cted Unrestricted
Royaltiesa Prod Taxa Perm. Fundb to Unres. GF Genera 1 Fundc Genera 1 Fund
1982 $1,538.98 $1,602.74 $384.7 5 $2,756.98 $4' 114.90 $4 '114. 90
1983 1,186.87 1,212.05 296.72 2,102.20 3,137.61 3,137.61
1984 1,113.13 1,137.27 27 8. 28 1,972.12 2 943.46 2,943.46
1985 1,091.76 1, 085.42 272.94 1,904.24 2,842.15 . 2,842.15
1986 1,213.86 1,196.81 303.47 2,107.21 3,145.09 2,841.62
1987 1,338.46 l,305.81 334.62 2,309.66 3,447.25 3,112. 63
1988 1,362.95 1,143.77 340.74 2,165.98 3,232.81 2,892.07
1989 1 ,410. 83 1,184.17 352.71 2,24 2. 29 3,346.70 2,993.99
1990 1,264.18 982.18 316. 0 5 1,930.32 2, 881.07 2,565.02
19 91 1,062.02 799.73 26 5. 51 1,596.25 2,382.46 2,116.95
1992 95 7. 86 73 0. 39 239.4 7 1,448.79 2,162.37 1,922.90
19 93 84 5. 61 581.03 211.40 1,215.24 1,813.79 1,602.39
1994 761.41 503.56 190.35 1,074.62 1,603.91 1,413.56
1995 642.21 416.98 160.55 898.64 1,341.25 1,180.70
1996 588.45 347.47 147.11 788.81 1,177.33 1,030.22
1~_97 569.47 338.04 14 2. 37 765.14 1,142.00 999.63
1998 551. 73 323.43 137.93 73 7. 2 3 1,100.34 962.41
Total $17,499.78 $14,890.85 $4,374.97 $28,015.72 41,814.49 $37,439.52
a Oil and gas production tax receipts and royalties: Department of Revenue, computer run dated 7/16/82. Projections
were in nominal dollars; converted to real dollars for this table using inflation factor provided by Departr.1ent of
Reve.nue. Between 1982 and 1998, an inflation rate of 7.67 percent per year was assumed.
brermanent Fund contribution: assumed to be 25 percent of royalties. The actual rate will be higher in some of these
years due to the increased contribution rate legislated for newer leases.
c Unrestricted General Fund revenues before Energy Fund deposit. In FY 82, oil and gas production taxes and royalties
after deducting the Permanent Fund deposit, represented about two-thirds of unrestricted General Fund revenues. This
percentage was applied to each year to approximate the total unrestricted revenues before the Energy Fund deposit.
This may be an optimistic assumption; the Department of Revenue shOI'IS that oil and gas production taxes and royalties
less the P.F. deposit, are projected to account for 73 percent and 74 percent of unrestricted General Fund revenues in
FY 83 and FY 84. If one of these higher figures had been assumed, the total unrestricted general fund revenues sho'ftn
in column x would be lm·1er. Note: A projection of t-otal unrestricted general fund revenues for this period was not
available from the Department of Revenue.
d Susitna financing requirements. Annual expenditures for Susitna construction in FY 82 dollars, ,Jack Kreinheder,
SECTION 6
REVIEW AND ASSESSMENT OF
DEBT FINANCING FOR
POWER PROJECTS
INTRODUCTION
One of the compelling reasons, if not the primary reason, for
the formation of the Authority was to provide an entity that would
have the statutory authority and practical capability to undertake
major financings for power projects. Although the scope of the
Authority's responsibilities, in this regard, has changed from its
creation in 1976, power project financing remains among the Author-
ity's primary responsibilities.
This section of the report provides the results of our review
and assessment of debt financing under Task 6. This review covered
both present and planned practices with respect to interim and long
term debt financing.
During the'period that we were involved in the work under
Task 6, a working group which included Authority staff and the
Authority's bond counsel, financial advisor, and lead
underwriters were involved in a comprehensive review of long term
debt financing alternatives. Thro~gh the cooperation of the
Authority and members of the working group, we have been able to
review the progress of their work as well as provide comments to·
them.
On October ll, 1982, the Authority's Executive Director trans-
mitted to the board a "Plan of Finance for Alaska Power Authority
Projects" which was developed by the working group. We have
included in this section of the report a summary of our assess-
ment of the content of this document.
6-l
STATUTORY DIRECTIVES RELATED TO DEBT FINANCING
,The Authori~y's statutory directives relating to financing
are provided in Chapter 83, Article 3 of Alaska Statutes
(44.83.100 -44.83.160). The significant provisions of these
sections are summarized below.·
Bonds of the Authority
The Authority is authorized to borrow money as one of its
general powers. This authority includes, but is not limited to, the • issuance of bonds on which the principal and interest are payable:
exclusivley from the income and receipts, or other money derived
from the project, or designated projects (whether or not they are
financed in whole or in part with the proceeds of the bondsj; from
its income.and receipts or other assets generally, or a designated
' part or parts of them; from one or more revenue-producing contracts
including a contract providing for the security of the bonds.~
Bond issues are authorized by a resolution of the Authority.
The specifics of resolutions are left to the Authority's discretion,
with one limitation-~that no bond may mature more than 50 years from
the date of its issue. Other than this, a resolution of the
Authority may provide: the date of issue and term to maturity; the
form, denomination, rate of interest, medium of payment, and the
places and terms of redemption. The Authority also determines the
time or times of offerings, the price or prices, and the method of
sale--public or private.
A special provision applies to bonds for power projects under
the Energy Program for Alaska. The Authority can borrow money by
issuing its bonds if appropriations to the Power Development Fund
are insufficient to cover the total cost of acquiring or con-
structing the power project, and the cost of financing (the bond's
interest rate) is less than any other alternative available. Prin-
cipal and interest are paid from money derived from the sale of
power from the financed power projects.
6-2
Trust Indentures and Trust Agreements
The Authority has the discretion to determine the form of
security for each bond issue. Security may consist of a trust
indenture or trust agreement between the Authority and a
corporate trustee, or it can be obtained through a secured loan
agreement or other .instrument. A third alternataive is to pass a
resolution which grants specific powers to a corporate trustee.
A trust agreement must also contain a covenant by the Authority
that it will at all times maintain charges, fees, or rates that are
sufficient to meet its obligations and that a wholesale power con-
tract between the Authority and another party for the sale, trans-
mission, or distribution of power shall establish charges sufficient
to pay: the costs of operation and maintenance of the project; the
principal and interest on bonds issued under the trust agreement; a
debt service coverage amount (the size necessary to market its bon~s
is deter~ined by the Authority); for renewals, replacements and
improvements of the project; for the maintenance of a reserve as
required by the terms of the trust agreement.JA}'
To secure issues of its bonds th~ Authority establishes one
or more special funds, called "capital reserve funds". These
funds are established if the Authority determines that they will
enhance the marketability of its bonds. Proceeds from the sale of
its bonds, or any other money supplied to the Authority for the same
purpose as those proceeds, are paid into a capital reserve fund.
All money held in the fund must be used for bond payment and/or
redemption.
Income or interest earned by a capital reserve fund may be
transferred to other accounts or funds by the Authority.
However, the amount transferred must n6t reduce the a~ount within
the fund below the capital reserve fund requirement (which is
established by a resolution of the Authority). This same rule
applies when the Authority wishes to issue additional bonds
secured by such a capital reserve fund.
6-3
General Financial Provisions
The statute specifies that a pledge made with respect
to bonds is valid and binding from the time the pledge is made.
Furthermore, bonds issued by a public corporation do not constitute
an indebtedness or other liability of the State of Alaska or of a
political subdivision of the State. Any claims are payable solely
from. the income and receipts or other funds or property of the
Authority. However, the State does pledge that it "will not limit
or alter the right~ and powers vested in the Authority by this
chapter to fulfill the terms of a contract made by the Authority •
until the bonds • • • and all costs and expenses in connection
with an action or proceeding by or on behalf of holders, are fully
met and discharged.l2/
. .
One final point which must be recognized is that these bond
agreements and trust indenture provisions must be read in context
with the provisions of the Energy Program for Alaska. The language
presented here may not be strictly applicable in instances where
project debt service is pooled among several power projects. This
is important to note because a debt financed project will not neces-
sarily be responsible for all of its debt service, since HB 9 pro-
vides for a limited equalization of debt service between projects.
INTERIM DEBT FINANCING
The interim financing of power project construction is a
common practice in the industry. Under typical interim financing
arrangements, a debt instrument is issued for a term up to a
short period after completion of construction or some date
certain to provide construction funds required in excess of those
provided as an equity investment. This interim financing is then
"taken out" or paid from the proceeds of long term debt or a
combination·of long term debt and additional equity investment.
Authority Interim Debt Financing Program
The Authority has utilized interim debt financing in
connection with three of the four major hydroelectric projects
,•
6-4
•
presently under construction (Solomon Gulch was financed entirely
from appropriations by the Legislature). The $200 million pro-
ceeds of these tax exempt issues have supplemented funds
appropriated by the Legislature tor construction of those
projects.
Swan Lake Project Interim Debt Financing
In May of 1981 the Authority issued $35 million of series
1981 General Obligation Bonds for a term of three years. These
bonds were purchased by a consortium of banks under terms of ·an
agreement that provided for semi-annual interest payments at an
interest rated pegged at 65 percent of the Morgan Guarantee Trust
Company prime rate, not to exceed 13 percent. The agreements
further provided that i~ the calculated rate were below the
ceiling it would be adjusted to compensate the lenders for
interest that would have been paid in prior periods had there
been no ceiling.
Under these agreements, the proceeds of the bond sale were
loaned by the Authority to the City of Ketchikan for construction of
Swan Lake. The bonds were secured by the general obligation of the
Authority and by all proceeds of any refunding bonds as well as the
agreements between the Authority and the City of Ketchikan. The
loan to the City of Ketchikan was se~ured by proceeds of any Ketchi-
kan public utility refunding bonds, certain revenues and amounts in
the utility's revenue fund, and all moneys in the Swan Lake Con-
struction Fund. The agreement with the City provided identical
terms with respect to other matters and the same interest provisions
as did the Authority's bonds and its agreements with the purchasers
·-~of those · bon·ds. "'· ·
The Swan Lake project interim financing was somewhat atypical
for several reasons. First, the Authority was obtaining interim
financing for a project that it did not own. Also, the Authority
utilized a general obligation bond as the financing vehicle and
these bonds were sold at a variable rate pegged to the prime rate
with a cap.
The maturity of the bonds issued by the Authority for the Swan
Lake project is the earliest of the interim financing undertaken to
6-5
date. These, therefore, will be the first interim financing debt
instruments that will be refunded through the issuance of long term
debt, assuming that the legislature does not appropriate sufficient
funds to meet this obligation.
Tyee and Terror Lake Projects Interim Debt Financing
In providing interim debt financing for the Tyee and Terror
Lake projects, the Authority issued Variable Rate Demand Notes
(notes) supported by bank letters of credit. This is typical of the
interim financing arrangements for power projects in other parts of
the country.
Interim financing for the portion of the Tyee costs in excess
of State appropriations was undertaken in January of 1982 with the
issuance of $50 million of notes. Terror Lake interim financing was
completed in May, 1982, with the issuance of $115 million of notes.
The notes are general obligations of the Authority, payable from:
0
0
0
Amounts on deposit and interest earnings under the
Authority's note resolution.
Drawings under the letters of credit issued by banks.
The proceeds of long term bonds of the Authority
issued for permanently funding the costs of Tyee
and Terror Lake projects.
The issuance of notes did not involve a pledge of the faith and
credit nor the taxing power of the State of Alaska or any political
subdivision.
The variable rate interest on the notes is pegged at 1/4 of 1
percent above the "Tax Exempt Note Rate" (TENR). This is an index
which reflects the current bid-side yields on short term tax exempt
securities (U.S. Government guatanteed housing projec~ notes, other
high quality municipal notes and tax exempt commercial paper). This
rate is announced on a weekly basis by the Bankers Trust Company.
This interest rate arrangement brings the interest rate paid by the
Authority very close (within 1/4 of 1 percent) to the highest grade
tax exempt short term securities.
6-6
Authority Interim Debt Financing Policy
On October 11, 1982, the Authority's Executive Director
transmitted a financing policy statement to the Authority's
board. A copy of this communication, which was the Authority's
response to the request in the legislative letter of intent filed
with HB 9, is included as Appendix 6-A. This policy statement
provided the following guidelines:
0
0
0
0
0
Permanent financing for the project can be obtained
when interim financing matures.
The interim financing matures no sooner than six months
after the expected date of project completion.
Short term rates offer an interest cost savings over
long term financing.
At least 75 percent of the project cost is under
contract when the interim financing is authorized.
Where possible, the interim financing combined with the
available resources should fully fund the remaining
cost of the project, plus an adequate contingency.
Assessment of the Authority's Interim Debt
Financing Program and Policy
The use of interim debt financing has to be an important
part of the Authority's overall financing program as well as
specific financing plans for individual projects. we are in
general agreement with both the approach used by the Authority in
its interim financing to date and the advantages of an interim
financing program as set forth in Appendix 6-A.
Authority Interim Debt Financing Program
As outlined above, the Authority's initial interim debt
financing involved issuance of short term general obligation
bonds in connection with the Swan Lake project. When this financing
was undertaken, the Authority, in effect, acted as an intermediary
6-7
between the City of Ketchikan and the capital market. The interest
rate charged on the general obligation bonds reflected what was then
a short term rate for tax exempt borrowers. Therefore, although the
use of general obligation bonds for interim financing is not common
practice, the results were successful.
In the interim financing for the Tyee and Terror Lake projects,
the Authority moved to a more conventional interim financing
arrangement with the issuance of variable rate notes. The Tyee
interim financing involved the sale of variable rate notes which
were supported by a letter of credit from Bankers Trust Company.
Subsequent interim financing for Terror Lake was made on the same
basis but the banks supporting the financing through letters of
credit were expanded to include First Interstate Bank of California
and Mellon Bank. This reflected a continuing maturity of the Autho-
rity's interim financing program.
The ultimate test of the validity of the Authority's interim
financing program is, of course, market acceptance of the securities
involved and the interest rate that must be paid. One evidence of
the success of the Tyee and Terror Lake interim financings was the
fact that the financing was successful and rated by Moody's as "MIG
1", which is their highest rating for short term securities.
Another is that the pegging of the interest rate to the TENR has
brought the Authority's interest cost into the range of interest
paid on the highest quality tax exempt short term financings.
Authority Interim Debt Financing Policy
The Executive Director's communication,which is included as
Appendix 6-A, in our view, presents a concise analysis of the
benefits of interim financing as well as the pollcyguidelines
for its use. As we have stated, we believe that interim
financing has to be an important part of the Authority's overall
financing program. We are therefore supportive of the policy
set forth in this document.
There are really only two areas of risk associated with
utilizing interim financing for construction. The first is that
at the time long term debt is issued to "take out" the interim
financing, market conditions might be worse than they were at the
6-8
time interim financing was undertaken. This would mean that the
Authority might pay a higher rate of interest for the long term
debt than they would have had they issued long term debt
initially. In the extreme, the Authority might find the market
condition such that it was unable to finance on a long term basis
the amounts involved in the interim financing.
There is however, a remedy to this situation. In the event
that the Authority is forced into the market for tne issuance of
long term debt during periods of very high interest rates, sub-
sequently, the bonds issued could be refunded when the market
returns to what would be considered a more "normal" level. In the
event that the market, for whatever reason, would not accept long
term debt issues, arrangements can be made to roll over the interim
financing until market conditions improve.
The second area of risk is that a project might be terminated.
If this were the case, the outstanding interim financing that had
been expended would have to be paid off and it probably would not be
possible to convert this to long term financing in any conventional
way. This risk is not limited to interim financing but wo1,1ld be the
same, and perhaps more complicated, if long term debt had been
issued initially to finance construction. We do not consider either
of these risks to be persuasive in an argument against utilization
of interim debt financing.
One of the main advantages of interim financing is that it
postpones going to the capital markets with a long term debt
issue until projects are completed. Without exception, this will
result in more favorable terms for the long term financing than
if such financing was undertaken prior to completion of the
projects. Initiating long term debt financing after completion
of the pro)ects means .. that the Authority can go to market .with a
completed operating project and power sales contracts in place,
guaranteeing payment for the.project output. In effect, the
financing is made on the basis of a "going business" as opposed
to a project in some stage of construction with the inherent
uncertainties.
6-9
Authority Interim Financing Alternatives
The arrangements used for interim debt financing, as well
as long term debt financing, are almost exclusively a function of
market acceptability. These arrangements change over time as new
approaches are introduced and ultimately accepted. For this reason
it is absolutely crucial that the Authority continue to work closely
with its financial advisors and lead underwriters as well as with
its bond counsel. It is our observation that this has been the
Authority's practice and we encourage its continuation.
One area that the Authority and its financial advisors may
want to explore as time passes is the potential use of tax exempt
commercial paper in conjunction with whatever form of interim
financing might be used. Particularly, the issuance of tax
exempt commercial paper in combination with variable rate notes
might be useful in leveling cash flow from State appropriations.
For example, if the flow of State appropriations for a given
fiscal year did not "mesh" with the projected flow of expendi-
tures based on those appropriations, short term commercial paper,
supported by letters of credit from the Authority's bankers,
could be used to assure the availability of funds required by the
construction schedule.
LONG TERM DEBT FINANCING
To date, the Authority has not undertaken any long term debt
financing. However, the maturity schedules of interim financing
necessitate the Authority's entering the long term market sometime
within the next year. As previously discussed, in anticipation of
this the Authority s~aff and the Authority's bond counsel, financial
advisor, and lead underwriters have undertaken a review of long term
debt financing alternatives. The results of this work were summa-
rized in the "Plan of Finance for Alaska Power Authority Projects"
which was transmitted to the Board by the Authority's Executive
Director on October 11, 1982.
We have included this document as Appendix 6-B. Our assessment
of its content is summarized in this section of the report.
6-10
Assessment of "Plan of Finance for
Alaska Power Authority Projects"
First, we do not consider this document to be a financing
plan for a particular project. Ratner, it represents a general
statement of principles conceFning long term debt financing
that might be undertaken for several projects. We have covered
the subject of a financing plan for specific projects elsewhere
in this report and, therefore, our comments on the document
included as Appendix 6-B are made in the context of the overall
financing program in the Authority. These comments are made on a
section .by section basis.
Objectives
The objectives stated in the plan are not its substance.
However, they are broad enough that they provide for a rational
approach to debt financing. If, however, this document were to
be redrafted, consideration might be given to relating objectives
to statutory directives provided by the Legislature.
Summary
Our comments on the material provided in the summary are
included under the several headings of the document. One point,
however, relates to the proportion of debt to equity tha·t might be
maintained by the Authority. We would agree that bond marketing
and rating considerations are important in determining some
optimum level of debt to equity. But, for the Authority, in the
final analysis, the level of equity provided is determined by the
Legislature through its appropriations.to individual projects
constructed by the Authority.
Timing
As previously discussed, we are very supportive of the interim
financing program undertaken by the Authority and the principles of
future interim financing included in Appendix 6-A. With respect to
6-11
the potential sales of long term debt prior to project completion
our inclination is to defer to the advice of the Authority's finan-
cial advisor and lead underwriters. But, we would suggest that
consideration be given, to the extent practicable, to the scheduling
of maturities on interim financing to occur a few months after
scheduled project completion in order that the long term debt issue
would be made when the project was actually in operation. We do not
believe that this approach would impact the level of capitalized
interest which would continue until the project was completed no
matter what the source of tunds. such an approach would totally
remove any construction risk for those who might purchase the Autho-
rity's long term debt instruments.
Debt Instruments
We agree that the Authority should first look to the
issuance of revenue bonds, as opposed to general obligation
bonds. We would suggest that the scheduling of maturities on
individual bond issues or on bond issues for a specific project
not be set as a matter of policy. Market conditions, from time
to time, may dictate that the maturities of a particular issue
may be shorter than a 35 year period to take advantage of more
favorable interest rates. The Authority's policy, therefore,
might better provide that the total debt service for all
outstanding indebtedness would be structured in such a way that
it would approximate a levelized 35 year debt service.
Security
The security for the Authority~s bonds as set forth in the
policy is, for the most part, dictated by the Legislature's statu-
tory directives relating to financing. The language of the policy
does not clearly indicate that the bonds to be issued w i 11 be reve-
nue bonds. There is a suggestion that the assets of the Authority
might also be pledged as security for such bonds. If this be the
case, the debt instrument would be something more than a revenue
bond in that it would provide some type of mortgage on the Author-
ity's assets. rhis point aside, we agree that the bonds issued by
6-12
the Authority, except in special cases, should be supported by a
pledge of their total revenues as opposed to the revenues of a
particular project. This approach provides a broader security for
the debt instrument which should result in more favorable interest
rates.
The policy also provides that future bonds would be issued on a
parity basis. That is, that the-Authority proposes to covenant that
it would not issue bonds in the future that would have a prior claim
on the Authority's revenues pledged .as security for previously
issued bonds. We agree that this is a necessary requirement. We
note that the Authority will reserve the right to issue bonds for a
specific project separately from the system bonds and that the
revenues from that project might be p~edged solely to the benefit of
that project's bondholders. Even if this were never done, the
reservation of such a right is clearly necessary to preserve maximum
flexibility in future financings.
Reseryes
One of the most important areas of the policy relates to the
reserves that will be provided in connection with the issuance of
long term debt. Each of the reserves set forth in the policy are
discussed below.
Debt Service Reserve
A debt service reserve is a necessary condition for the
succesful marketing of revenue bonds. As an industry practice
this reserve is set at a minimum, and most often at a level
equal to the maxi~um ~rinrial debt seivic~ o~ o~tst~nding bonds.
For perspective, the debt service reserve on the basis of
maximum annual debt service, assuming that the bonds issued
will in total have level annual debt service, for the Swan,
Terror, and Tyee projects will be approximately $25 million
annually. This is the amount, therefore, that would have to
be deposited into the debt service reserve by the time that
the interim financing on these three projects is replaced by
long term debt.
6-13
The working group has considered, and the Authority's
plan at least hints, that the debt service would be funded
through appropriations by the Legislature~ This would mean
that the Legislature would be required to appropriate
approximately $25 million in addition to the approximately
$260 million already appropriated for the four projects
under construction (Solomon, Swan, Terror, and Tyee). This,
clearly, is an alternative.
Another alternative, which we understand has been consi-
dered by the working group, would be to borrow the debt service
reserve. This would mean the bond issue would have to include,
among other things, approximately $25 million to fund the debt
service reserve. This is not an uncommon practice in revenue
bond financings for major projects. In fact, it is the most
common approach.
The advantage of providing funds through appropriation for
the debt service reserve is that another increment of "equity"
would be provided by the State for these projects This would
enhance the evaluation of the bonds by potential bond buyers as
well as rating agencies. If additional amounts are borrow~d to
fund a debt service reserve, annual debt service payments will
have to be made on these amounts. However, the debt service
reserve is invested by the trustee, and if the interest
earnings on the amounts invested approximate the interest to be
paid, in effect, the money is obtained for "free". Generally
speaking, it is possible to achieve a balance of interest
earnings and interest cost on reserve accounts. However, there
are times when this cannot be done and the interest required to
be paid on the reserve accounts becomes a project cost. This
would impact the level of rates required from each of the
projects, although the impact would be relatively small when
compared to the total revenue·that has to be raised.
Regardless of how the debt service reserve is funded,
consideration should be given to structuring the reserve in
such a way that it is available for the debt service on any and
all projects financed through the sale of parity bonds. In
other words, we are suggesting that the debt service reserve
not be segregated by bond issue, but rather that it be a
6-14
"pooled" reserve. This approach would make it possible to
utilize the reserve to pay more than one year's debt service on
a particular project if that became necessary.
Operation and Maintenance Reserve
A reserve for operation and maintenance costs, beyond
financing considerations, is generally considered to be "pru-
dent business". This is particularly true in the case of
hydroelectric systems where water flow variations might impact
. the level of revenues in a particular year.
The Authority's plan indicates that this reserve would
be equivalent to six months of estimated systemwide opera-
tion and maintenance costs. Further, although the plan does
not specifically address the question of funding, it appears
that this reserve would also be funded by legislative appro"'""
priation. Again, an alternative would be to borrow the
funds for this reserve.
With respect to the level of this reserve, six months
would appear to be a minimum when measured against industry
practice. It is not uncommon to provide an operation and
maintenance reserve equal to one year's costs. However, an
additional six months of reserves may not have to be provided
initially. An alternative would be to provide the initial
six months, either from bond proceeds or by appropriation,
and then supplement this annually for a period of several
years from the debt service coverage amount included in
rates until the reserve becomes equal to one year's opera-
tion and maintenance costs.
Inflation's effect on the-reserve balance must also be
considered. Escalation of operation and maintenance costs will
cause the reserve balance, although adequate in the previous
period, to fall below the desired level in a future period. If
the reserve is to be maintained at a constant level in real
terms, an annual deposit w i 11 have to be made to cover infla-
tion. Again, this could be handled from the debt service
coverage component of rates. This is discussed further under
the heading "Flow of Funds".
6-15
As discussed in the case of the debt service reserve, the
operation and maintenance reserve should also be maintained on
a pooled basis rather than earmarking portions of the reserve
for specific projects.
Renewal and Replacement Fund
As with the operation and maintenance reserve, the renewal
and replacement fund is established on the basis of financing
and practical considerations. This reserve is intended to
provide funds for the interim replacement of major pieces of
mechanical and electrical equipment that can be expected to
"wear out" before the project reaches the end of its useful
life. We have previously discussed the renewal and replacement
fund requirements in Section 4 of the report.
The Plan of Finance suggests that this fund would be
established in an amount equal to 5 percent of the cost of
projects included in the system. For the most part, the con-
cern for renewal and replacement relates to equipment as
opposed to structures, the latter being the most significant
component of project cost. A more direct approach, therefore,
is to peg the level of funding of the renewal and replacement
fund to the cost of equipment as opposed to total project cost.
The appropriate formula to establish the level of this fund is
a matter of judgment and we would defer to the project design
engineers as well as the Authority's operating staff on this
question. However, our expreience indicates that utilities
with substantial hydroelectric generation have utilized a for-
mula that is based on providing 1/20 of the balances in the
FERC capital accounts covering equipment annually.
Rate Covenant
The plan envisions that a rate covenant would be made providing
that the Authority would maintain rates at a level sufficient to
recover operation and maintenance costs, any required deposits to
reserve funds, and at least 1.10 times average annual debt service
6-16
on all outstanding system revenue bonds. Such a covenant is attrac-
tive in the marketing of bonds, and, as a practical matter, must be
met if the Authority is to cover .its obligations.
It is not uncommon for a ·covenant to be made with respect to
the level of rates before additional bonds might be sold. For
example, an additional bonds covenant might ·require that revenues
would be sufficient to provide the rate components enumerated above
including the debt service and coverage on the additional bonds. If
this is the case it is also common that this test be made on the
basis of an adjustment to reflect the additional revenue that will
be derived from the project or projects for which the additional
bonds are sold.
So long as the components of rates included in rate covenants
are those that statutorily or as a matter of policy will be in-
cluded in the calculation of the actual rates, then they can be
made without imposing an additional burden on the Authority's
ratepayers. Given the benefit of such covenants to debt financing,
they are clearly advantageous.
Flow of Funds
The Plan of Finance provides that revenues be deposited as
follows:
First, to fund the operation and maintenance account to
the extent required to pay operation and maintenance
expenses of the system;
Next, to the principal and interest account until equal
to the riext scheduled payment of interest and
principal;
Next, to restore, if necessary, the debt service reserve,
the operation and maintenance reserve, and the renewal and
replacement reserve to the required balances;
Next, any remaining revenues would be deposited in the
retained coverage account of the Authority to be used
first to restore the deficiencies in the reserves, and
then as equity contribution to the future projects autho-
rized by the Legislature, and the revenues of which are
pledged to the system revenues.
6-17
This concept introduces the generation of funds from rates to pro-
vide equity in future projects from revenues. These funds would be
the balance of the 10 percent of annual debt service that would be
provided in rates as debt service coverage.
With respect to debt service cover~ge, we concur that it is
absolutely necessary that rates be set at a level to provide some
coverage of the annual debt service if the Authority is to utilize
revenue bond financing. Based on our experience, the 10 percent
level proposed in the Plan should be considered a minimum. It may
be found, over time, that there would be some benefit in providing a
higher level of coverage even though the covenants would only
require the 10 percent coverage that is included in the Plan.
Additional Parity Bonds and Permitted Indebtedness
The Plan sets forth four conditions that would have to be
met before any additional parity bonds could be issued for
improvements to existing projects or new projects that might be
added to the system:
0
0
0
0
New projects would not benefit from any legislatively
mandated power rate limit.
An independent nationally recognized consulting firm
would provide a finding of technical and financial
feasibility, including a finding that project revenues
-would be at least equal to annual operation and
maintenance expense and 1.1 times maximum annual debt
service for the additional debt required to construct
the project.
An independent, nationally recognized consulting
engineering firm shall have concluded that the project is
needed, technically and financially feasible, compatible
with existing resources, and that under these requirements
wholesale rates for all projects, except so-called
"capped" rate projects, do not increase and may decline,
depending on the initial year power sales of the added
project.
In the first full year following project completion, the
ratio of additional annual debt service to total project
cost cannot exceed the systemwide ratio of annual debt
service to project costs.
6-18
One exception would be provided to these tests. This would
per~it the issuance of completion bonds having a par value no
greater than 15 percent of the project cost for which they were
issued.
These conditions for the issuance o~ additional bonds are, in
our view, reasonable and generally consistent with similar provi-
sions that will be found in bond .resolutions of other agencies. The
requirement for a finding that revenues from the project to be
financed will be sufficient to cover operation and maintenance costs
and debt service plus coverage is consistent with the rate covenants
previously discussed.
OTHER CONSIDERATONS
j
In the Authority 1 s financing of projects it faces a somewhat
unique problem due to the fact that large areas of the State a~e
served by rural electric cooperatives as opposed to municipal
utilities. To the extent that the output of Authority projects is
sold to these utilities there is a restriciton on the issuance of
tax exempt bonds. Unless a particular project will qualify under
other provisions of law for tax exempt financing, the Authority may
be faced with the situation where some taxable debt instruments
would have to be issued. This problem has been, and continues to
be, considered by the Authority and its consultants.
6-19
ALASI-i.A POWER AUTHORITY
APPENDIX 6-A
October 11, 1982
Mr. Charles Conway, Chairman
Alaska Power Authority
2481 Belmont Drive
Anchorage, Alaska 99503
Subject: Interim Financing for Alaska Power Authority Projects
Dear Chuck:
To date the Alaska Power Authority has issued interim financing
having a total outstanding par amount of $200 million for the following
projects:
Swan Lake
Tyee Lake
Terror Lake
S 35 million
50 million
115 million
In each instance the interim financing was incurred in order to
proceed with the award of contracts ~hich wo~ld ot~e~wise have exceeded
. the amount of funds on hend. It is expected that when due, the interim
financing will be replaced with permanent financing in the form of
long-term revenue bonds or additional direct State appropriations.
Interim financing offers advantages of cost and flexibility where
the following circumstances apply:
l)
2)
3)
4)
Full funding at project costs is required to obtain the best
bids and to avoirl project completion delays.
The Legislature has evidenced a desire to consider iidditicna1
direct funding for a project out of funrls available i1 a
subsecuent fiscal year.
Short-term rates offer a significant cost savinqs at the time
of issuance and market risks are hedged.
The Authcritv and its financial team have determined that it
should defe~ long-term financing until market conditions are
mol~e favorable.
The use of interim financina need not tonstrain future tett
issuance policies of the Authorify, but purchasers or providFrs ~f
credit facilities wil1 ~ant enforceable agreeme1ts reqa~ding the
Authority's intenticn to issue a long-term debt that is oroper1y secured
an~, he1ce, marketable. In t~is regara, interim lenders norm2 1 iy ~xoec~
6-20
..
Mr. Charles onway
October 11, 982
Page 2
that lon9-term ~inancing will be secured by contracts for the sale of
the power produced by the project being constructed. This eXDP.ctation
is not unreasonable, especially ir view of the fact that it is starriard
industry practice to conclude such power sales agreements prior to award
of contracts and initiation of construction.
Therefore, it is the policy of the Alaska Power Author~ty to use
interim financino under the followino auidelines: ~ J J
1. Permanent financin9 for the project can be obtained when the
interim financing matures.
2. The interim financing matures no sooner than six months after
the expected date of project completion.
3. Short-term rates offer a substantial advantage over lon9-term
financinq and future market risk has been incorporated ir.
this segment.
4. At least 75% of the project cost is under contract when the
interim financing is authorized.
5. Where possible, the interim financing combined with the
available resources should fully fund the remaining cost of
the .project, plus an adequate contingency.
This brief letter is the Auth6rity's response to the request in the
Letter of Intent filed with H.B.9 concerning interim financing.
CVj~ Eric P. Yould
Executive Director
6-21
ALAS!L:~ POWER AUTHORITY
APPENDIX 6-B
Mr. Charles Conway, Chairman
Alaska Power Authority
2481 Belmont
Anchorage, Alaska 99503
Subject: Plan of Finance
Dear Chuck:
October 11, 1982
The attached 11 Plan of Finance 11 sets forth a recommended financing
structure that ~ttill meet the Alaska Power Authority's operational
objectives while complying with both State and Federal leqislation and
regulatory constraints. · ~
<:c~elyS?, y ~
Eric P. Yould \
Executive Director
Attachment: As stated
6-22
Objective:
Summary:
..
PLAN OF FINANCE FOR ALASKA POWER AUTHORITY PROJECTS
To es-tablish a financial structure for the Alaska
Power Authority which
l) Provides power to Alaskans at rates below the costs
of alternative fossil fuel generation resources.·
2) Assures an optional mix of direct State funding and
externally raised debt financing.
3) Encourages local electric utilities to participate
in the statewide power system and to assume a share
of its costs.
4) Assures continuing access to the nation's capital
markets for such amounts as are needed on terms and
conditions favorable to the Authority and its power
purchasers.
5) Affords flexibility to meet unforeseen
circumstances affecting the Authority, the State
and its economy.
Projects of the Authority will be financed from a mix
of tax-exempt debt, direct State appropriations or
reinvestment of retained coverage. The tax-exempt
bonds will be general obligations of the Authority to
be repaid from the aggregate annual revenues of the
Authority whether or not such revenues represent
payments for power, investment income or other fees
and charges.
For the system as a whole, the proportion of debt to
equity will be determined by bond marketing
requirements, rating agency consideration, the terms
of agreements with bondholders and the terms of power
sales agreements with participating utilities.
Systemwide revenues must at least equal 110 per cent
of maximum annual debt service (except for certain
obligations incurred in connection with interim
financing), costs of system operation and maintenance
and additional amounts as necessary to fund certain
reserve funds.
The portion of required annual revenues to be derived
from each project in the Statewide system is determined
by ap~lication of the formula established in H.B.9 or
a sim~lar mechanism authorized by the Legislature and
implemented by the Board of Directors of the Authority.
6-23
Plan of Finance for
Alaska Power Authority Projects
Page 2
Timing:
Debt Instruments:
Security:
Absent special circumstances in the capital markets or
the project constructio~ schedule, it is expected that
State appropriations will be spent first and that debt
will not be incurred until project construction has
proceeded sufficiently as to eliminate or reduce most
of the uncertainties that might have generated
substantial cost overruns or project delays. Such a
financing schedule avoids unnecessary capitalized
interest and allows external financing to be completed
with little remaining construction ris~.
While a variety of forms of interim or short-term
financing may be used during construction of certain
projects, it is assumed that most projects will be
permanently financed with tax-exempt revenue bonds
having a maturity of approximately 35 years.
h~ere other forms of permanent financing are used, it
is expected that their cash flow requirements will
approximate those of long-term tax-exempt bonds.
The bonds would be issued as general obligations of
the Authority payable from any unrestricted assets or
revenues of the Authority. The principal assets of
the Authority will be the projects.built.by the
Authority and financed as part of tha system, and its
right to payments under power sales agreements entered
into with the purchasers of power from projects in the
system.
In addition, the bonds would be secured by amounts in
a debt service reserve (equal to maximum annual debt
service on all outstanding system bonds), an operation
and maintenance reserve (equal to estimated systemwide
operation and maintenance costs for 6 months)'· a
renewal and replacement fund (equal to 5% of the cost
of the projects in the System) and any amounts held in
the Authorily's retained coverage account. With the
exception of the retained coverage account, these
reserves would be initially funded from legislative
appropriation and subsequently increased from the same
source upon the issuance of additional bonds.
The debt service reserve fund would benefit from the
moral obligation language contained in the Authority's
authorizing statute.
6-24
,,
"
Plan of Finence for
Alaska Power Authority Projects
Page 3
Rate Covenant & Flow
of Funds:
The Authority would covenant to grant no special
security or preferred standing to any bondholders or
with respect to any system project through a pledge of
revenues or other security device. However, projects
outside the system could be financed through a pledge
of their revenues solely for the benefit of that
project's bondholders.
Individual project rates would be set pursuant to the
legislatively mandated formula, but the aggregate
revenue derived would be covenanted to be at least
equal to the sum of operation and maintenance, any
required deposits to systemwide reserve funds
(operation and maintenance, debt service, and renewal
and replacement), and at least 1.10 tirr.es aver<::ge
annual debt service on all outstanding system revenue
bonds.
As received, revenues would be deposited as follows:
First, to fund the operations and maintenance
account to the extent required to pay operation and
maintenance expenses of the System.
Nexi:, to the principal and interest account until
equal to the next scheduled pa)~ent of interest and
principal;
Next, to restore, if necessary, the debt serv~ce
reserve, the operation and maintenance reserve and
the renewal and replacement reserve to their
required balances;
Next, any remaining revenues would be deposited in
the retained coverage account of the Authority to
be used first to restore deficiencies in reserves,
and then as equity contribution to future projects··
authorized by the Legislature, and the revenues of
which are pledged as system revenues.
In the event revenues are insufficient to meet
scheduled principal or interest payments, the Trustee
would withdraw amounts as needed from the debt service
reserve fund. The debt service reserve fund would
benefic from the moral obligation provided by statute.
In additioh, withdrawals from the debt service reserve
fund would be immediately resto::-ed frcm amounts in the
surplus accoun't, the renewal and replacement reserve
6-25
Plan of Finance for
Alaska Power Authority Projects
Page 4
and the operating and maintenance reserve,
respectively. The Autnority may adj~st rates as
necessary, whether or not as provided by the wholesale
power rate formula, to provide revenues sufficient to
restore the debt service reserve fund, renewal and
replacement reserve and operating and maintenance
reserve by the end of the Authority's next fiscal
year. Any subsequent revenues not required to meet
operating and maintenance expense to pay debt service
or to restore the debt service reserve fund shall be
used first to restore the operating and maintenance
fund, then the renewal and replacement fund, and then
deposited to the retained coverage account.
~ '
Power Sales Contracts: The output of each project in the system would be sold
pursuant to power sales agreements unique to that
project. Within the system, the power from some
projects would be sold under strict take-or-pay,
''hell-or-high-water" contracts, others under
requirement contracts, some as demand charges, some
for firm energy, others for secondary. The
appropriate arrangement would depend on IRS
considerations, physical factors relating to
interconnection and competing sources of power, and
the composition of existing and projected demand ~n
the market served by each project.
Power sales agreements would be concluded ·prior to
initiating construction of any prcject.
Regardless of the exact form of agreement, each
project would be expected to sell power at rates and
in amounts sufficient to generate revenues equal to
1) Its proportionate share of debt service and
coverage,
2) Its direct: costs of' operation and maintenance, and
3) Restore reserves.
In addition, the agreements and the covenants with
bondholders would provide for a step-up in each
project's wholesale power rate to temporarily absorb a
systemwide revenue shortfall due to interruption of
service or payment default at other projects in the
system. Coverage on a systemwide basis would assure
that interruption of service or default on one or two
of the smaller projects could be absorbed within the
system.
6-26
..
Plan of Finance for
Alaska·Power Authority Projects
Page 5
Wholesale Cost of
Power:
Additional Parity
Bonds and Permitted
Indebtedness::
For certain purchasers there may be need to limit
amounts of power self-generated or purchased from non-
Authority sources.
The allocation of systemwide debt service and
associated costs has been the subject of repeated
legislative deliberations. H.B.9, which currently
governs this matter, provides for the allocation of
systemwide debt service to each project in proportion
to the ratio of that project's cost to total system
cost. The wholesale cost of power for that project is
then the sum of its share of annual.debt service, its
share of coverage and its direct operating costs
divided by kilowatt-hours sold.
Attached as an appendix ~s a mathematical study of the
affect on rates as new projects having different cost,
capacity, debt/equity ratio and utilization rates are
added to the system.
Additional bonds could be issued to finance additions
or improvements to projects already in the system, and
to finance construction of new projects to be added to
the system, provided that:
1) New projects did not benefit from any legislatively
mandated power rate limit.
2) An independent, nationally recognized consulting
engineering firm shall have concluded that the
project is needed, technically and financially
feasible, compatible with existing resources and
that project revenues will be at least equal to
annual operation and maintenance and 1.10 times
·maximum annual· debt service for the additional· debt
required to ~onstruct the ·project •
3) In the first full year following project completion
the ratio of additional annual debt service to
total project cost cannot exceed the systemwide
ratio of annual debt service to project cost as
determined in 198
4) An independent, nationally recognized consulting
engineering firm shall have concluded that the
project is needed, technically and financially
feasible, compatible with existing resources, and
6-27
Plan of Finance for
Alaska Power Authority Projects
Page 6
Ratings:
that under these requirements wholesale rat"es for
all projects, except so-called "capped" rate
projects, do not increase and ~ay decline,
depending on the initial year power sales of the
added project.
In addition, without regard to these tests, completion
bonds having a par value no greater than 15% project
cost may be issued.
Interim notes and oth~r short-~erm indebtedness could
be issued to temporarily finance construction costs of
power projects. Such notes or other short-term
indebtedness would be payable from moneys held in the
retained coverage account and the proceeds of system
bonds thereafter issued to permanently finance the
project.
Rating analysis would begin with an evaluation of the
financial and operating strength of the Authority and
the power system it owns and operates. The system's
strength would be its size, geographic and market
diversity and the substantial equity contributions of
the State. Ultimately, a rating of the system tekes
on the character of a rating of the principal centers
of economic activity in Alaska. However, in the early
years of the system's creation it will be vulnerable
to a single project default, outage or failure to
achieve projected power sales.
For this reason it will be essential to provide
through legislative appropriation sufficient Authority
reserves to absorb problems associated with one
project without resorting to the moral obligation.
Having evaluated the economic strengths of the syst~m
and its revenues, the rating services will consider,
among others, the following items:
1) Type of power sales contracts and the resulting
allocation of project risks, marketing risks and
risks of catastrophic loss.
2) Probability that projected load growth and project
utilization will be realized.
3) Arrangements for project construction operation and
maintenance and the experience and expertise of
personnel involved.
6-28
Plan of Finance for
Alaska Powe~ Authority Projects
Page 7
Bond Marke t:lng:
Allocation of Project
Risk:
10/ll/82
ATD/ar
4) Adequacy of reserves and rate revision powers to
meet adverse operating experience.
The combined security of the Authority's general
obligation, its statewide power sales revenues,
state-funded systemwide reserve funds and access to
the State Legislature through the moraJ. obligation
feature gives an investor several liyers of security
and of a dollar magnitude suf£icent to meet all but a
systemwide crisis. In addition, the financial
interconnection of projects while not equivalent to
physical connection, provides the benefit of
diversifying certain economic and geotechnic risks.
At least in part, the focus of credit analysis is
shifted away from individual utility systems and
toward a statewide analysis of power needs, resources
and state financial strength.
Investors will devote special attention to limitations
on future projects that can be added to the debt of
the system so that they are assured that uneconomic or
infeasible projects will not be allowed to dilute
bondholder security.
By its very nature, system financial structure will
alter t~e allocation of project risk to include the
power purchaser, the Authority and, contingently, the
State of Alaska. Thus, the magnitude of resources
available more nearly approaches the range of probable
losses. In addition, the expertise of the Authority
qualify it to better manage and control the project
risks.
6-29
..
SECTION 7
REVIEW AND ASSESSMENT OF
ALTERNATIVES FOR DISPOSITION OF
PROJECTS UPON COMPLETION
As projects developed and financed by the Authority are com-
.pleted, the question of who shall own and operate them becomes
timely. These questions have been raised from a number of quarters
and they were included as part of the scope of work of the Study.
OWNERSHIP OF COMPLETED PROJECTS
O~r discussions with the Authority's bond counsel and investment
bankers indicate that there is little flexibility with regard to the
question of ownership of completed projects. If the Authority under-
takes debt financing for a particular project, title to that project
will have to be vested with the Authority. It is suggested that any
further questions on this subject should be directed to the Autho-
rity's bond counsel or the Attorney General.
This situation is not different from that found in the lower 48
states. In recent years there has been a definite trend away from
the development and ownership of projects by individual utilities.
Project development has, by and large, been undertaken either by a
consortium of utilities acting jointly with one designated as a
project manager, or by so-called joint action agencies. In the case
of projects developed by a consortium of utilities, each of which
contributes money to the project, the participating utilities own an
undivided interest in the project in proportion to their financial
participation. In the case of projects developed by joint _action
agencies, the situation is similar to that faced by the Authority.
If the joint action agency issues debt to finance a project, it then
must own the project.
7-1
PROJECT OPERATION AND lv1AINTENANCE
With respect to the operation and maintenance of completed
projects, there is considerably rno~e flexibility. Financing
considerations dictate that assurance be provided that the projects
will be operated and maintained by ~n agenacy that is competent to
do this work. Therefore, any arrangement for operation and
maintenance will have to be disclosed at the time of financing.
Beyond this, however, the decision as to the entity that will
operate.and maintain projects developed and financed by the
Authority is one that would be made on the basis of relative
economics and political considerations.
General Utility Practice
Almost without exception, utilities operate those projects
which they develop and finance. With the advent of projects that
involve the participation of a number of utilities, the general
practice has been that one of those utilities is designated as the
project manager. Most commonly, this will be the utility that has
the largest ownership share in the project or the utility in-whose
service area the project is located. An operating committee corn-
posed of representatives of each of the utilities that oversee the
operations generally determines the operational arrangement for the
projects.
For projects developed by joint action agencies--that is
agencies formed primarily for the purpose of construction of power
projects--there are two basic alternatives. If the agency is
comprised of utilities that do not have their own major generation
projects, or if the agency is developing a number of large pro-
jects, it is likely that the agency will develop a capability
for project operation and will perform this function. In cases
where one or more of the participating utilities in the joint
action agency do operate their own generation it is not uncommon
that one of these utilities will, under contractual arrangements,
assume the role of the project manager and operator.
7-2
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Alternatives for Operation and Maintenance
of Authority Projects
There are three basic alternatives for operation and main-
tenance of projects developed and financed by the Authority:
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The Authority could operate and maintain one or more of
the projects that they finance.
One or more projects could be operated by local utilities
serving the area where the project is located under a
contractual arrangement with the Authority.
One or more projects could be operated by local utilities,
as described above, with the Authority maintaining certain
responsibilities with respect to maintenance and
overhaul work.
The operation and maintenance decision should be made on the
basis of the economics involved, and, of course, political consider-
ations. If a particular project is located within the service
area of a utility that is already capably operating similar pro-
jects, then serious consideration should be given to a contractual
relationship under which that utility would operate the Authority's
project. If the project location is not as described above, then
either the Authority or some other entity will have to develop
operational staff at the project location. Here, the decision
should be based on who can provide the most economical and efficient
service. It should be noted that the Authority has contracted with
the City of Ketchikan for the operation of the Swan Lake project.
This is certainly consistent with the discussion above.
As the several projects that are now under construction are
completed, the Authority may operate some projects itself with
individual utilities operating others. To provide appropriate
management control over projects that are operated by the Autho-
rity and to maintain a capability for oversight and inspection of
projects operated by local utilities, the Authority is developing
an operating staff. We believe that this effort reflects a
prudent business approach given that a number of projects are
near completion. Beyond the decision as to what entity will
operate a particular project, consideration should be given to
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the potential savings of centralizing, with the Authority, cer-
tain responsibilities with respect to maintenance and overhaul
work. The Authority may find that it is efficient to maintain a
centralized inventory of certain parts. Also, it may be more
efficient for the Authority to maintain a staff qualified to
undertake heavy maintenance and overhaul work. This staff might
consist of supervisory personnel that would be available to
oversee work at all projects or, depending on the capability of
individual utilities, it may be advantageous to actually maintain
crews that could perform this work.
Operation and Maintenance of Other
State Funded Projects
In the course of our work it was observed that a number of
power generation facilities have been constructed throughout the
State with funds appropriated by the Legislature or obtained from
state agencies other than the Authority. We understand that, at
least in some cases, long term arrangements are not always made for
the operation and maintenance of these facilities.
It has been suggested that a procedure be established to assure
that generation facilities constructed with State funds are properl~
operated and maintained so that the full benefits can be enjoyed by
the people that they are intended to serve. We believe that con-
sideration should be given to establishing a requirement, as a
condition of providing funds, that the service area make arrange-
ments for operation and maintenance before funds are actually
provided. For example, the Alaska Village Electric Cooperative
might be able to efficiently fulfill this function in the bush area.
In other areas of the State, utilities could serve this function if
the generation facility was sited in their service area~
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The time frame within which the forecast was to be prepared
and the guidelines under which it was conducted made such
utility involvement difficult, if not impossible, to achieve
in a meaningful way.
As of this writing this interconnection appears essentially
assured of proceeding.
The general appr~ach used in the Bristol Bay Regional Power
Plan Detailed Feasibility Analysis, as described in the July
1982 Interim Feasibility Assessment prepared for the
Authority, appears to provide a reasonable model for the type
of market area analysis which could be incorporated at the
reconnaissance study stage, perhaps in less detail.
l5/ Examples are Tyee Lake, Black Bear, and Old Harbor.
~ A nominal dollar energy cost projection is an estimate of
future energy costs including estimated inflation. This
represents an estimate of what.the costs are expected to be
in the year that they are incurred.
ill A method of evaluating the savings in power cost for each
dollar of capital investment in a project.
l]J Most notably, the Co~ps of Engineers and the u.s. Department
of Energy. ·
l]/ An overnight capital cost is an estimate, in today's
dollars, of what it would cost to construct a project today,
ignoring. the anticipated escalation of the capital cost
which would occur over the actual period required for
project planning and construction.
2QJ Article 3 AAC 94.060 Alaska Power Authority, Register 81,
April 1982.
2lJ Article 3 AAC 94.065, Alaska Power Authority, Register 81,
April 1982.
221 The provisions described would apply only to proposed new
projects which will generate more than 1.5 megawatts of
power and which require an appropriation from a State fund
or are based on a plan of finance which requires a pledge of
·the credit of the State. These provisions would also apply
to a project which will generate more than 25 megawatts of
power and whose cost of construction will require the
issuance of Authority revenue bonds. Finally, these provi-
sions would apply to electrical transmission or distribution
facilities which cost more than $3,000,000 to construct, or
to additions or modifications which cost more than
$1,000,000.
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1982 SPECIAL REPORTS
HOUSE RESEARCH AGENCY
82-A State Loan Programs: A Review of Administration, Funding
and Activity
December 1982
82-B State Budget Policy Under Uncertain Revenue Forecasts:
Options for Legislative Action
January 1983
.B2-C Power Project Development and Financing in Alaska
January 1983
82-D Election District Breakdown of State Operating and Capital
Budgets: Fiscal Years 1981 -1983
82-E Adult Corrections in Alaska: Current Issues in Administration
and Management
Jan u a ry 19 83