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FORM 10-K--ANNUAL REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
(As last amended in Rel. No. 34-31327, eff. 10-21-92)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(x)Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 2000
( )Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the transition period from______________________to_________________________
Commission file Number 33-42125
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Chugach Electric Association, Inc.
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(Exact name of registrant as specified in its charter)
Alaska 92-0014224
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(State or other jurisdiction of
incorporation or organization) (I.R.S. Employer Identification No.)
5601 Minnesota Drive, Anchorage, Alaska 99518
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (907) 563-7494
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
- ------------------------------------ ------------------------------------------
- ------------------------------------ ------------------------------------------
Securities registered pursuant to Section 12(g) of the Act:
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(Title of class)
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(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securites Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. /x/ Yes / / No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. N/A
State the aggregate market value of the voting stock held by non-affiliates
of the registrant. The aggregate market value shall be computed by reference
to the price at which the stock was sold, or the average bid and asked prices
of such stock, as of a specified date within 60 days prior to the date of
filing. (See definition of affiliate in Rule 405, 17 CFR 230.405). N/A
CHUGACH ELECTRIC ASSOCIATION, INC.
2000 Form 10-K Annual Report
Table of Contents
PART I Page
Item 1 - Business 1
Item 2 - Properties 8
Item 3 - Legal Proceedings 15
Item 4 - Submission of Matters to a Vote of Security Holders 15
PART II
Item 5 - Market for Registrant's Common Equity and Related
Stockholder Matters 15
Item 6 - Selected Financial Data 16
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations 17
Item 7A - Quantitative and Qualitative Disclosures About Market Risk 26
Item 8 - Financial Statements and Supplementary Data 28
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 51
PART III
Item 10 - Directors and Executive Officers of the Registrant 51
Item 11 - Executive Compensation 53
Item 12 - Security Ownership of Certain Beneficial Owners and Management 56
Item 13 - Certain Relationships and Related Transactions 56
Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K 56
SIGNATURES 66
CAUTION REGARDING FORWARD-LOOKING STATEMENTS
Statements in this report that do not relate to historical facts, including
statements relating to future plans, events or performance, are forward-looking
statements that involve risks and uncertainties. Actual results, events or
performance may differ materially. Readers are cautioned not to place undue
reliance on these forward-looking statements, that speak only as of the date of
this report and the accuracy of which is subject to inherent uncertainty.
Chugach Electric Association, Inc. (Chugach or the Association) undertakes no
obligation to publicly release any revisions to these forward-looking statements
to reflect events or circumstances that may occur after the date of this report
or the effect of those events or circumstances on any of the forward-looking
statements contained in this report, except as required by law.
PART I
Item 1 - Business
General
Chugach Electric Association, Inc., is the largest electric utility in
Alaska. We are engaged in the generation, transmission and distribution of
electricity to approximately 71,800 metered locations in the Anchorage and upper
Kenai Peninsula areas. Through an interconnected regional electrical system, our
energy is distributed throughout Alaska's Railbelt, a 400-mile-long area
stretching from the coastline of the southern Kenai Peninsula to the interior of
the state, including Alaska's largest cities, Anchorage and Fairbanks. Neither
we nor any other electric utility in Alaska has any connection to the electric
grid of the mainland United States or Canada.
Through direct service to retail customers and indirectly through
wholesale and economy energy sales, we provide some or all of the electricity
used by approximately two-thirds of Alaska's electric customers. We also supply
much of the power requirements of three wholesale customers, Matanuska Electric
Association ("MEA"), Homer Electric Association ("HEA") and the City of Seward
("Seward"). In addition, on a periodic basis, we provide electricity to
Anchorage Municipal Light & Power ("AML&P"). AML&P has about 30,000 meters.
We have approximately 511 megawatts of installed generating capacity
provided by 17 generating units at our five owned power plants: Beluga Power
Plant, Bernice Lake Power Plant, International Generating Station, Cooper Lake
Hydroelectric Plant and Eklutna Hydroelectric Project, in which we own a 30%
interest. Approximately 96% (by rated capacity) of our generating capacity is
fueled by natural gas, which we purchase under long-term gas contracts. The
remainder of our generating resources are hydroelectric facilities. In 2000,
approximately 85% of our energy was generated at our Beluga facility. We
purchase up to 27.4 megawatts from the Bradley Lake Hydroelectric Project and up
to 40 megawatts from the Nikiski power plant on the Kenai Peninsula. We operate
1,602 miles of distribution line and 402 miles of transmission line. For the
year ended December 31, 2000, we sold 2.4 billion kilowatt hours ("kWh") of
power.
We were organized as an Alaska electric cooperative in 1948.
Cooperatives are business organizations that are owned by their members. As
not-for-profit organizations, cooperatives are intended to provide services to
their members at cost, in part by eliminating the need to produce profits or a
return on equity. Today, cooperatives operate throughout the United States in
such diverse areas as utilities, agriculture, irrigation, insurance and credit.
All cooperatives are based upon similar principles and legal foundations.
Because members' equity is not considered an investment, a cooperative's
objectives and policies are oriented to serving member interests, rather than
maximizing return on investment.
Our members are the consumers of the electricity sold by us. As of
December 31, 2000, we had approximately 57,900 retail members receiving service
at approximately 71,800 metered locations and three major wholesale customers.
No individual retail customer receives more than 5% of our power. Our business
and affairs are managed by the General Manager and are overseen by a
seven-member Board of Directors. Directors are elected at large by the
membership and serve three-year staggered terms. Each member is entitled to one
vote. In addition to voting for directors, members have voting rights with
respect to mergers and the sale, lease, or other disposition (except by mortgage
or deed of trust) of all or a substantial portion of our property.
Our customers are billed per a tariff rate on a monthly basis for
electrical power consumed during the preceding month. Billing rates are approved
by the Regulatory Commission of Alaska ("RCA") (see "Rate Regulation and Rates"
below).
Rates (derived from the historic cost of service basis) may generate
revenues in excess of current period costs (net operating margins and
nonoperating margins) in any year and such excess is designated on our
Statements of Revenues, Expenses and Patronage Capital as "assignable margins."
Retained assignable margins are designated on our balance sheet as "patronage
capital" that is assigned to each member on the basis of patronage.
We are a rural electric cooperative that is exempt from federal income
taxation as an organization described in Section 501(c)(12) of the Internal
Revenue Code ("Code"). Alaska electric cooperatives must pay to the State of
Alaska, in lieu of state and local ad valorem, income and excise taxes, a tax at
the rate of $0.0005 per kWh of electricity sold in the retail market during the
preceding year. In addition, we collect a regulatory cost charge of $.000318 per
kWh of retail electricity sold. This charge is assessed to fund the operations
of the RCA. It is a pass-through and thus does not impact our margins.
Our workforce consists of approximately 355 full -time employees.
Approximately two-thirds of our employees are members of the International
Brotherhood of Electrical Workers ("IBEW"). We have three collective bargaining
agreements with the IBEW that are in effect through June 30, 2003. We also have
an agreement with Hotel Employees, Restaurant Employees, Local 878 in effect
through June 30, 2003. We believe our relationship with our employees is good.
Our Service Areas
Our service areas and those of our wholesale and economy energy
customers are often described collectively as the Railbelt region of Alaska
because the three geographic areas (the Southcentral, the Kenai Peninsula and
the Interior) are linked by the Alaska Railroad.
Anchorage is the trade, service and financial center for most of Alaska
and serves as a major center for many state governmental functions. Other
significant contributing factors to the Anchorage economy include a large
federal government and military presence, tourism, air and rail transportation
facilities and headquarters support for the petroleum, mining and other basic
industries located elsewhere in the state.
The Matanuska-Susitna Borough is immediately north of the Municipality
of Anchorage, centered around the communities of Palmer and Wasilla. Although
agriculture, tourism, mining and forestry are factors in the economy of the
Matanuska-Susitna Borough, the economic well-being of the area is closely tied
to that of Anchorage and many Matanuska-Susitna residents commute to jobs in
Anchorage.
The Kenai Peninsula is south of Anchorage with an economy substantially
independent of the Anchorage area. The most significant basic industry on the
Kenai Peninsula is the production and processing of petroleum products from the
Cook Inlet region. Other important basic industries include tourism and fish
harvesting and processing. Principal communities on the Kenai Peninsula are
Homer, Seward, Kenai and Soldotna.
Fairbanks is the center of economic activity for the central part of
the state (known as the Interior). Fairbanks (250 air miles north of Anchorage
and about 400 air miles south of Alaska's northern border) is Alaska's second
largest city. Basic economic activities in the Fairbanks region include federal
and state government and military operations, the University of Alaska, tourism
and support of natural resource development in the Interior and northern parts
of the state. Recently a major gold mine commenced operation near Fairbanks. The
Trans-Alaska Pipeline System (which transports crude oil) passes near Fairbanks
on its route from the North Slope oilfield to Valdez.
Competition
Nationwide, the electric utility industry is entering a period of
unprecedented upheaval and restructuring. We have taken several steps to be more
effectively positioned to meet the challenge of a competitive market for
electricity.
We have been active at the Alaska Legislature in support of the
customer's right to choose their electric power supplier. For example, we have
requested access over a neighboring utility's distribution and transmission
system and asked the RCA to enforce the request. The RCA ruled that retail
competition is permitted in Alaska only after prior review and approval by the
RCA. We are appealing this ruling in the courts. Virtually all other Alaskan
utilities have opposed our efforts to develop competition and are treating their
service territories as exclusive. At this time no bill relating to customer
choice has moved out of legislative committee. It is not possible to predict the
outcome of this legislative process.
We have made organizational changes in preparation for competition.
Recognizing that the new marketplace will probably be "unbundled" along the
functional lines of generation, transmission and distribution and retail
services, our organizational structure reflects these functions. Operating with
three divisions: Finance and Energy Supply, Transmission and Distribution
Network Services and Retail Services, we have positioned ourselves to meet
competition in the electric industry. We continue to operate a key account
program for larger customers and are developing new services to enhance existing
customers' satisfaction.
It is our objective to continually improve the efficiency and cost
effectiveness of our operations. We participate in customer satisfaction
surveys, benchmark the performance of system operations against an international
peer group and perform studies on how to implement business process best
practices. These ongoing programs focus on distribution and transmission lines,
substations, power plants, fleet operations and administrative services.
Rate Regulation and Rates
We are subject to rate regulation by the RCA. We can seek increases in
our demand and energy charges by filing general rate cases with the RCA. While
the formal ratemaking process typically takes nine months to one year, it is
within the RCA's authority to authorize, after a notice period, rate changes on
an interim, refundable basis. In addition, the RCA has been willing to open
limited reviews of matters to resolve specific issues from which expeditious
decisions can often be rendered.
The RCA has exclusive regulatory control of our rates, subject to
appeal to the Alaska Superior Court and the Alaska Supreme Court under the
Alaska Administrative Procedures Act. Under Alaska law, financial covenants of
an Alaskan electric cooperative contained in a debt instrument will be valid and
enforceable, and rates set by the RCA must be adequate to meet those covenants.
We will continue to recover changes in our fuel and purchased power
expenses through routine fuel surcharge filings with the RCA. See "Management's
Discussion and Analysis - Results of Operations - Rate Regulation and Rates."
The 1991 Indenture governing all of our outstanding bonds requires us
to set rates designed to yield margins for interest equal to at least 1.20 times
total interest expense. The authorized rate-setting Times Interest Earned Ratio
("TIER") level of 1.35 has allowed us to achieve margins for interest greater
than 1.20. For the year ended December 31, 2000, our achieved TIER was 1.39.
Sales to Customers
The following table shows the energy sales to and electric revenues
from our retail, wholesale, and economy energy customers for the year ended
December 31, 2000:
Percent of Total
MWh 2000 Revenues 2000 Revenues
--- ------------- ---------------
Direct retail sales:
Residential 509,799 $ 51,288,657 33%
Commercial 582,652 47,248,033 31%
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Total 1,092,451 $ 98,536,690 64%
Wholesale sales:
MEA 549,517 $ 27,252,051 17%
Homer 436,112 19,060,244 12%
Sewar 59,454 2,369,550 2%
----------- ----------- ----
Total .. 1,045,083 $ 48,681,845 31%
Economy energy sales(1) 267,855 $ 7,820,998 5%
---------- -------------
Total sales to customers 2,405,389 $155,039,533 100%
========= ====
Miscellaneous energy revenue $ 2,331,133
------------
Total energy revenues $157,370,666
============
(1) All economy sales were made to GVEA.
Retail Customers
Service Territory
Our retail service area covers the populated areas of Anchorage (other
than downtown Anchorage) as well as remote mountain areas and villages. The
service area ranges from the northern Kenai Peninsula on the south, to Tyonek on
the west, to Whittier on the east and to Fort Richardson on the north.
Customers.
We directly serve approximately 71,800 meters. We have approximately
57,900 members (some members are served by more than one meter). Our customers
are primarily urban and suburban. The urban nature of our customer base means
that we have a relatively high customer density per line mile. Higher customer
density means that fixed costs can be spread over a greater number of customers.
As a result of lower average costs attributable to each customer, we benefit
from a greater stability in revenue, as compared to a less dense distribution
system in which each individual customer would have a more significant impact on
operating results. For the past five years no retail customer accounted for more
than 5% of our revenues.
Wholesale Customers
We are the principal supplier of power to MEA, Seward and Homer under
separate wholesale power contracts. For 2000, our wholesale power contracts
produced $47.4 million in revenues, representing 31% of our revenues and 43% of
our total kWh sales to customers.
MEA and Homer
We have two power sales contracts with AEG&T and each of MEA and Homer.
AEG&T is a generation and transmission cooperative formed by MEA and Homer.
Under each of these contracts, we sell power to AEG&T, which resells the power
to MEA and Homer. Each of MEA and Homer is obligated to pay us for the power
sold to AEG&T for its use if AEG&T does not pay.
Our contract for the benefit of MEA obligates MEA (through AEG&T) to
purchase all of its electric power and energy requirements from us.
Contractually, MEA has the right, on advance notice and subject to RCA approval,
to convert to a net requirements purchaser of power, and as such MEA would be
obligated to buy its needed power from us net of its power needs satisfied from
any of its own or AEG&T's resources. The notice period required for such
conversion may be up to five years, depending on which non-Chugach resources MEA
proposes to use to satisfy its power needs.
After conversion to a net requirements purchaser under the contract,
MEA cannot reduce the payment for power it purchases from us below a certain
minimum amount. If MEA converts to net requirements service, MEA will be
required to pay demand charges based upon the highest post-1985 historical
coincident peak on the MEA system. Therefore, we will continue to recover fixed
costs if MEA converts to net-requirements service. Also, our revenues from
energy sales to MEA would partially decline in proportion to the reduction in
the energy sold, but this decline would be offset to an extent by savings in the
variable costs associated with energy production.
MEA also has the right, on seven years advance notice and subject to
RCA approval, to convert to a take-or-pay purchase of a fixed amount of power,
also subject to minimum payment requirements associated with prior purchases.
The MEA contract is in effect through December 31, 2014. This contract does not
protect us against loss of load resulting from retail competition in MEA's
distribution service territory if retail competition is ever permitted in
Alaska. It is not possible at this time to estimate the potential impact on our
revenues that could result from such competition. See "Competition" above.
During the past several years, we have had numerous disputes and
engaged in substantial litigation with MEA regarding many aspects of our
contractual relationship with it. For example, in October 1998, the Board of
Directors of MEA announced that it had offered to acquire Chugach. Our Board of
Directors rejected the MEA acquisition proposal. MEA circulated a petition and
gathered a sufficient number of signatures from our members so that a special
meeting of our members was called for the purpose of considering MEA's proposal.
This meeting was held November 18, 1999, at which time our members
overwhelmingly rejected the MEA proposal. No further action regarding this offer
has been initiated by MEA. For a discussion of material pending litigation
between MEA and us, see "Legal Proceedings."
Our contract for the benefit of Homer obligates Homer (through AEG&T)
to take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per
year. The Homer contract includes certain limitations on the costs that may be
included in our rates charged to Homer. The Homer contract expires on January 1,
2014. Homer's remaining resource requirements are provided by AEG&T's Nikiski
cogeneration facility and AEG&T's entitlement for power from the Bradley Lake
hydroelectric project for the benefit of Homer. In February 1999, we entered
into a dispatch agreement with AEG&T to operate the Nikiski unit as a Chugach
system resource. The agreement provides that, in addition to the energy that we
already sell to AEG&T and Homer, we will sell energy to AEG&T equal to Homer's
residual energy requirements less its allocated share of the Bradley Lake
project, up to a maximum of 320,000 MWh per year. A portion of the Nikiski unit
output may be dispatched for Homer needs in excess of the sum of our contract
demand plus Homer's share of energy from the Bradley Lake project. The dispatch
agreement will terminate in 2014 coincident with our power supply contract for
the benefit of Homer.
Seward
We currently provide nearly all the power needs of the City of
Seward. In February 1998, we entered into a new power sales agreement with
Seward that allows us to interrupt service to Seward up to 12 times per year and
provides for a 1/3 reduction in the demand charge (approximately $350,000
annually). This agreement expires September 1, 2001, but we have negotiated an
amendment to the agreement that will extend its term to January 31, 2006. The
amendment was fully executed on December 12, 2000, and subsequently filed for
approval with the RCA on February 5, 2001, and will be effective upon approval
by the RCA.
Economy Customers
Since 1988, we have sold nonfirm (economy) energy to Golden Valley
Electric Association ("GVEA") under an agreement that expires in 2008. Under the
agreement, we use available generating capacity in excess of our own needs to
produce electric energy for sale to GVEA, which uses that energy to serve its
own loads in place of more expensive energy that GVEA would otherwise generate
itself or purchase from other sources. We use gas purchased from Marathon Oil
Company ("Marathon") to produce energy for sale to GVEA, and we charge GVEA a
rate sufficient to recover the gas cost, the costs of incremental operations and
maintenance expense resulting from increased use of our generators for GVEA, and
an agreed-upon markup or margin for each kWh sold.
In 2000, the RCA approved an amendment to our agreement with GVEA and a
settlement of an inter-utility dispute involving it. As a result, the market for
economy energy sold to GVEA has now been divided into two parts. The larger part
continues to be governed by our agreement with GVEA, which assures us of
priority in sales of such energy to GVEA. In general, we are assured of selling
to GVEA two-thirds of the first 450,000,000 kWh of economy energy and 80% of the
excess over 450,000,000 kWh of economy energy that GVEA purchases each year if
we are capable of producing that energy. Remaining economy energy sales to GVEA
have now become the "Economy Energy Spot Market." Sales in the Economy Energy
Spot Market are completely competitive among potential sellers of economy energy
to GVEA. Neither we nor any other seller
enjoys a contractual priority in making such sales. One of those
sellers, AML&P, is expected to dominate sales to GVEA in the Economy Energy Spot
Market for the immediate future, partly because AML&P prices its gas at less
than the Marathon gas on which we rely in making such sales.
Load Forecasts
The following table sets forth our projected load forecasts for the
next five years:
Load (MWh) 2001 2002 2003 2004 2005
---------- ---- ---- ---- ---- ----
Retail............ 1,118,259 1,138,639 1,162,634 1,187,001 1,213,582
Wholesale......... 1,114,376 1,179,616 1,206,385 1,234,757 1,263,427
Economy........... 260,000 260,000 260,000 260,000 260,000
Losses............ 138,428 142,505 145,613 148,847 152,218
--------- --------- --------- --------- ---------
Total.......... 2,631,063 2,720,760 2,774,632 2,830,605 2,889,227
Sales are expected to increase over the next five years principally due
to economic growth in the service sector. Based on a study by University of
Alaska, our total energy requirements are expected to grow at an average
compounded annual rate of 2.6% from 2001 to 2005--retail sales at 2.1% and
wholesale sales at 3.2%.
Item 2 - Properties
General
We have 511 megawatts of installed capacity consisting of 17 generating
units at five power plants. These include 368.1 megawatts of operating capacity
at the Beluga facility on the west side of Cook Inlet; 67.5 megawatts of power
at the Bernice Lake facility on the Kenai Peninsula; 46.7 megawatts of power at
International Generating Station in Anchorage; and 17.2 megawatts at the Cooper
Lake facility, which is also on the Kenai Peninsula. We also have 11.7 megawatts
of capacity from the two Eklutna hydroelectric plant generating units owned
jointly with MEA and AML&P. In addition to our own generation, we purchase power
from the 126 megawatt Bradley Lake hydroelectric project owned by the Alaska
Energy Authority ("AEA") through Alaska Industrial Development and Export
Authority. The Bradley Lake facility is operated by Homer and dispatched by us.
The Beluga, Bernice Lake and International facilities are all fueled by natural
gas. We own our offices and headquarters, located adjacent to our International
Generating Station in Anchorage. Warehouse space for some generation,
transmission and distribution inventory (including a small amount of office
space) is leased from an independent party.
Generation Assets
We own the land and improvements comprising our generating facilities
at Beluga and International. We also own all improvements comprising our
generating plant at Bernice Lake, located on land originally leased from Chevron
Oil Company and now owned by Homer, and our generating plant at Cooper Lake. The
Cooper Lake facility is located on federal land pursuant to a major project
license granted to us by the Federal Power Commission in 1957. The Bernice Lake
ground lease expires in 2011 and the federal license for the Cooper Lake
facility expires in 2007. We have no reason to believe that we will not be able
to renew the federal license or the Bernice Lake facility ground lease if
desirable.
In 1997, we acquired a 30% interest in the Eklutna Hydroelectric
Project. The plant is located on federal land pursuant to a United States Bureau
of Land Management right-of-way grant issued in October 1997.
Our principal generation units are Beluga 3, 5, 6, 7 and 8. These
units, comprising 334 megawatt capacity, meet most of our load. All other units
are used principally as reserve. While the Beluga turbine-generators are fairly
old, they have been maintained in good working order with periodic upgrades.
Beluga 3 had a major overhaul in 1996. Beluga 5 received a major overhaul in
1997. Beluga 6 was "repowered" in 2000 adding in excess of 25 years to its life.
Beluga 7 is slated for repowering in 2001. Beluga 8, a steam turbine, was
overhauled in 1994 and is slated for another major overhaul in 2002.
The following matrix depicts nomenclature, run hours for 2000 and
percentages of contribution and other historical information for all Chugach
generation units.
Percent of
Commercial Operation Rating Run hours Percent of total time
Facility Date Nomenclature (MW)(1) (2000) generation available
-------- ---- ------------ ------- ------ ---------- ---------
Beluga Power
Plant (3)
1 1968 GE Frame 5 19.6 1872.2 3.83 93.6
2 1968 GE Frame 5 19.6 2051.3 4.19 98.2
3 1972 GE Frame 7 64.8 7255.2 14.84 90.9
5 1975 GE Frame 7 68.7 8204.5 16.78 95.1
6 1975 ABB 11D-4A 69.4 3719.3 7.61 42.3
7 1978 ABB 11D-4A 71.0 8270.2 16.91 94.2
8 1981 BB DK-21150(2) 55.0 8419.0 17.22 95.8
Bernice Lake
Power Plant
2 1971 GE Frame 5 19.0 0 0 N/A
3 1978 GE Frame 5 26.0 4.7 0.01 99.4
4 1981 GE Frame 5 22.5 5953.1 12.17 99.7
Cooper Lake
Hydroelectric
Plant
1 1960 BB MV 230/10 8.6 1394.6 2.85 21.6
2 1960 BB MV 230/10 8.6 1530.9 3.13 21.6
International
Power Plant
1 1964 GE Frame 5 14.1 62.8 0.13 99.5
2 1965 GE Frame 5 14.1 99.2 0.20 99.9
3 1969 Westinghouse 191G 18.5 66.8 0.14 99.9
Eklutna
Hydroelectric
Plant (4)
1 1955 Newport News 5.8 N/A5 N/A5 N/A5
2 1955 Oerlikon custom 5.9 N/A5 N/A5 N/A5
System Total 48903.8 100.00
(1) Capacity rating in MW at 30 degrees Fahrenheit.
(2) Steam-turbine powered generator with heat provided by exhaust
from natural-gas fueled Units 6 and 7 (combined-cycle).
(3) Beluga Unit 4 and Bernice Lake Unit 1 were retired during 1994.
(4) The Eklutna Hydroelectric Plant is jointly owned by Chugach, MEA and
AML&P. The capacity shown is our 30% share of the plant's maximum
output.
(5) Because Eklutna Hydroelectric Plant is operated by MEA and managed by a
committee of the three owners, we do not record run hours or
in-commission rates.
Transmission and Distribution Assets
As of December 31, 2000, our transmission and distribution assets
included 39 substations and 402 miles of transmission lines, 931 miles of
overhead distribution lines and 659 miles of underground distribution line. We
own the land on which 20 of our substations are located and a portion of the
right-of-way connecting our Beluga plant to Anchorage. In the 1997 Eklutna
acquisition, we also acquired a partial interest in two substations and
additional transmission facilities.
Many substations and a substantial number of our transmission and
distribution rights-of-way are the subject of federal or state permits and
licenses. Under a federal license and a permit from the United States Forest
Service, we operate the Quartz Creek transmission substation, substations at
Hope, Summit Lake and Daves Creek, and transmission lines over all federal lands
between Cooper Lake on the Kenai Peninsula and Anchorage. Long-term permits from
the Alaska Division of Lands and the Alaska Railroad Corporation govern much of
the rest of our transmission system outside the Anchorage area. Within the
Anchorage area, we operate our University substation and several major
transmission lines pursuant to long-term rights-of-way grants from the U.S.
Department of the Interior, Bureau of Land Management, and transmission and
distribution lines have been constructed across privately owned lands pursuant
to easements across public rights-of-way and waterways pursuant to authority
granted by the appropriate governmental entity.
Title
Substantially all of our tangible and some of our intangible properties
and assets, including generation, transmission and distribution properties, but
excluding all excepted property identified in the 1991 Indenture, are pledged to
secure repayment of the 1991 Series A Bonds, the bonds issued to CoBank, and all
other bonds that may be issued under the 1991 Indenture.
In addition to the lien of the 1991 Indenture, many of our properties
are burdened by easements, plat restrictions, mineral reservation, water rights
and similar title exceptions common to the area or customarily reserved in
conveyances from federal or state governmental entities, and to additional minor
tide encumbrances and defects. We do not believe that any of these title defects
will materially impair the use of our properties in the operation of our
business.
Under the Alaska Electric and Telephone Cooperative Act, we possess the
power of eminent domain for the purpose and in the manner provided by Alaska
condemnation laws for acquiring private property for public use.
Other Assets
Bradley Lake. We are a participant in the Bradley Lake hydroelectric
project, which is a 126 megawatt rated capacity hydroelectric facility near
Homer on the southern end of the Kenai Peninsula that was placed into service in
September 1991. The project is nominally scheduled at 90 megawatts to minimize
losses and insure system stability. We have a 27.4 megawatt or 30.4% share in
the Bradley Lake project's output, and take Seward's and MEA's shares which we
net bill to them, for a total of 45% of the project's capacity.
The project was financed and built by AEA through grants from the State
of Alaska and the issuance of $166 million principal amount of revenue bonds
supported by power sales agreements with six electric utilities that share the
output from the facility (Chugach, AML&P, Homer and MEA (through AEG&T), GVEA
and Seward). The participating utilities have entered into take-or-pay power
sales agreements under which AEA has sold percentage shares of the project
capacity and the utilities have agreed to pay a like percentage of annual costs
of the project (including ownership, operation and maintenance costs,
debt-service costs and amounts required to maintain established reserves). We
also provide transmission and related services as a wheeling agent (one who
dispatches and transmits power of third parties over its own system) for all of
the participants in the Bradley Lake project.
The length of our Bradley Lake power sales agreement is fifty years
from the date of commercialization (September, 1991) or when the revenue bond
principal is repaid, whichever is the longer. We believe that, under a
worst-case scenario, we could be faced with annual expenditures of approximately
$4.1 million as a result of our Bradley Lake take-or-pay obligations. We believe
that this expense would be recoverable through a fuel surcharge. The share of
Bradley Lake indebtedness for which we are responsible is approximately
$44,000,000. Upon the default of a participant, and subject to certain other
conditions, AEA is entitled to increase each participant's share of costs and
output pro rata, to the extent necessary to compensate for the failure of
another participant to pay its share, provided that no participant's percentage
share is increased by more than 25%.
We negotiated with AEG&T a scheduling agreement whereby we schedule
AEG&T/Homer's share of the Bradley Lake project for the benefit of the Railbelt
electric system. AEG&T continues to pay its Bradley Lake project costs and
receives credit for the Bradley Lake energy generated for Homer. We pay a fixed
annual fee of $112,000 to AEG&T for these scheduling rights. This agreement
allows us to improve the efficiency of our generating resources through better
hydrothermal coordination.
Eklutna. We purchased a 30% undivided interest in the Eklutna
Hydroelectric Project from the federal government in 1997. MEA purchased a 17%
undivided interest in the Eklutna Hydroelectric Project. The power MEA purchases
from the Eklutna Hydroelectric Project is pooled with our purchases and sold
back to MEA to be used in meeting MEA's overall power requirements. AML&P owns
the remaining 53% undivided interest in the Eklutna Hydroelectric Project.
Fuel Supply
For 2000, 96% of our power was generated from gas, and 85% of that
gas-fired generation took place at Beluga.
Our primary sources of natural gas are the Beluga River Field producers
(Phillips Alaska, Inc. ("Phillips"), AML&P and Chevron USA Inc. ("Chevron"), and
Marathon. Phillips, AML&P and Chevron each own one-third of the gas produced
from the Beluga River Field and in 2000 provided approximately equal shares of
the Beluga gas. We have approximately 378 billion cubic feet ("BCF") of
remaining gas committed to us from the Beluga River Field producers and
Marathon. We currently use approximately 23 BCF of natural gas per year for firm
service. We believe that this usage will increase approximately 0.5 BCF per year
and estimate that our contract gas will last 15 to 19 years. The deliverability
requirements under the Beluga and Marathon contracts are in excess of the peak
winter demand requirements of the Beluga plant.
Beluga River Field Producers
We have similar requirements contracts with each of Phillips, AML&P and
Chevron that were executed in April 1989, superseding contracts that had been in
place since 1973. Each of the contracts with the Beluga River Field producers
provides for delivery of gas on different terms in three different periods.
Period 1 related to the delivery of gas previously committed by the respective
producer under the 1973 contracts and ended in June 1996.
During Period 2, which began in June 1996 and continues until the
earlier of the delivery of 180 BCF of natural gas or December 31, 2013, we are
entitled to take delivery of up to 180 BCF of natural gas (60 BCF per Beluga
River Field producer). During this period, we are required to take 60% of our
total fuel requirements at Beluga from the three Beluga River Field producers,
exclusive of gas purchased at Beluga under the Marathon contract for use in
making sales to GVEA or certain other wholesale purchasers. The price for gas
during this period under the Phillips and AML&P contracts is approximately 88%
of the price of gas under the Marathon contract (described below) ($1.8617 per
thousand cubic feet ("MCF") on January 1, 2001), plus taxes. The price during
this period under the Chevron contract is approximately 110% of the price of gas
under the Marathon contract (described below) ($2.3271 per MCF on January 1,
2001), plus taxes.
During Period 3 under the Beluga River Field producers' contracts,
which begins on the earlier of December 31, 2013, or the end of Period 2, we may
become entitled to take delivery of up to 120 BCF of natural gas (40 BCF per
producer). Whether any gas will be taken in Period 3, and the price and take
requirements with respect thereto, are to be determined in the future based upon
then-current market conditions.
We have supplemental, annually renewable contracts with the Beluga
River Field producers to supply supplemental gas (for peak periods of energy
usage) if they have it available in excess of the amounts guaranteed in the
basic contracts. The supplemental gas contracts raise the daily deliverability
of gas from the Beluga River Field producers to an aggregate of 85,200 MCF per
day. The base price of the gas under these contracts is the same as the base
price under the Marathon contract (described below), plus taxes.
Marathon
We entered into a requirements contract with Marathon in September 1988
for an initial commitment of 215 BCF. The contract expires on the earlier of
December 31, 2015, or the date on which Marathon has delivered to us a volume of
gas in total which equals or exceeds 215 BCF, which we currently expect to occur
by mid-2009. The base price for gas under the Marathon contract is $1.35 per
MCF, adjusted quarterly to reflect the percentage change between the preceding
twelve-month period and a base period in the average prices of West Texas
Intermediate Crude Oil (a benchmark of the Light Sweet Crude Oil Futures Index),
the Producer Price Index for natural gas, and the Consumer Price Index for
heating fuel oil. The price on January 1, 2001, exclusive of taxes, was $2.1156
per MCF.
Under the terms of the Marathon contract, Marathon generally provides
the primary supply of gas required for sales to GVEA, all of our requirements at
Bernice Lake and 40% of the requirements at Beluga. Marathon also has a right of
first refusal to provide additional gas under any sales agreements that we may
enter into with electric utilities we do not currently serve.
ENSTAR
We entered into a transportation agreement with ENSTAR Natural Gas
Company ("ENSTAR") in December 1992, whereby ENSTAR would transport our gas
purchased from the Beluga River Field producers or Marathon on a firm basis to
our International Power Plant at a transportation rate of $0.63 per MCF. In
addition, ENSTAR agreed to transport gas on an interruptible basis for
off-system sales at a rate of $0.30 per MCF. The agreement contains a minimum
monthly bill of $2,600 for firm service.
We hold a reservation to receive our gas requirements at International
Power Plant from ENSTAR under a tariff approved by the RCA in the event that the
transportation agreement is subsequently canceled. Under the currently suspended
tariff, ENSTAR is obligated to supply all of the gas we require at a price
approved by the RCA. There would be a monthly minimum bill of $10,465 but no
requirement to actually use any gas at the International Power Plant. The
estimated delivered price if the tariff were reinstated is $3.00 per MCF.
Environmental Matters
Our operations are subject to certain federal, state and local
environmental laws, which we monitor to ensure compliance. The costs associated
with environmental compliance are included as a component of both the operating
and capital budget processes. We accrue for costs associated with environmental
remediation obligations when such costs are probable and reasonably estimable.
We discovered polychlorinated biphenyls ("PCBs") in paint, caulk and
grease at the Cooper Lake Hydroelectric Plant during initial phases of a turbine
overhaul. We are implementing a plan approved by the Environmental Protection
Agency to remediate the PCBs
in the plant. We are also conducting an investigation to determine
whether any PCBs released from the plant are present in Kenai Lake. We do not
have an estimate at this time of the potential costs involved in the
investigation and we do not know whether any additional remediation will be
required.
Item 3 - Legal Proceedings
Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc.
On July 7, 1999, MEA filed a complaint against us in Alaska Superior
Court in Anchorage, asserting that we violated the Power Supply Agreement
between the parties, state statutes and our bylaws in failing to provide MEA
with information about several different matters that MEA asserts could affect
the cost of the power MEA purchases from us. MEA also asserted that we violated
the Power Supply Agreement in our management of our long-term bond indebtedness.
On February 8, 2000, MEA added a new claim in this proceeding. MEA
asked for an order directing that we be required to present our general rate
case filing to the Joint Rate Committee (an administrative body comprised of
representatives of Chugach and MEA) prior to presenting it to the RCA. We filed
our answer to MEA's Second Amended Complaint on March 10, 2000, opposing the
relief MEA requested.
Discovery in this matter is still in its preliminary stages. Trial is
set for February 2002. Because of the preliminary nature of the case, we are not
able to estimate the costs of our participation.
We have certain additional litigation matters and pending claims that
arise in the ordinary course of our business. In the opinion of management, no
individual matter or the matters in the aggregate is likely to have a material
adverse effect on our results of operations or financial condition.
Item 4 - Submission of Matters to a Vote of Security Holders
Not Applicable
PART II
Item 5 - Market for Registrant's
Common Equity and Related Stockholder Matters
Not Applicable
Item 6 - Selected Financial Data
The following tables present selected historical information relating to
financial condition and results of operations over the past five years:
Balance Sheet Data 2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Plant net:
In service $ 427,127,258 $ 398,544,496 $ 386,235,421 $ 393,228,853 $ 400,052,837
Construction work in
Progress 42,027,617 47,257,296 30,405,736 24,664,395 19,826,957
----------- ----------- ----------- ------------ ------------
Electric plant, net 469,154,875 445,801,792 416,641,157 417,893,248 419,879,794
Other assets 70,591,105 72,553,745 64,450,293 67,674,051 62,608,636
------------ ------------ ------------ ------------ ------------
Total assets $539,745,980 $518,355,537 $481,091,450 $485,567,299 $482,488,430
============ ============ ============ ============ ============
Capitalization:
Long-term debt 312,219,945 337,150,295 305,917,699 312,006,501 307,905,847
Equities and margins 128,815,340 122,524,645 114,023,296 109,119,697 104,477,942
----------- ----------- ----------- ----------- -----------
Total capitalization $441,035,285 $459,674,940 $419,940,995 $421,126,198 $412,383,789
============ ============ ============ ============ ============
Summary Operations Data
Operating revenues 158,541,114 142,644,327 141,825,373 143,947,730 134,876,668
Operating expenses 126,430,273 110,456,886 110,737,441 113,070,990 100,913,804
Interest expense 26,158,769 25,228,001 26,011,392 26,661,510 27,052,186
Amortization of gain on
Refinancing 1,440,479 1,092,620 1,542,723 1,577,149 1,703,136
----------- ----------- ----------- ----------- -----------
Net operating margins 7,392,551 8,052,060 6,619,263 5,792,379 8,613,814
Nonoperating margins 2,287,227 1,615,374 2,111,141 1,762,018 1,217,557
----------- ----------- ----------- ----------- -----------
Assignable margins $9,679,778 $9,667,434 $8,730,404 $7,554,397 $9,831,371
============ ============ ============ ============ ============
Item 7 - Management's Discussion and Analysis
of Financial Condition and Results of Operations
Caution Regarding Forward Looking Statements
Statements in this report that do not relate to historical facts, including
statements relating to future plans, events or performance, are forward-looking
statements that involve risks and uncertainties. Actual results, events or
performance may differ materially. Readers are cautioned not to place undue
reliance on these forward-looking statements that speak only as of the date of
this report and the accuracy of which is subject to inherent uncertainty. We
undertake no obligation to publicly release any revisions to these
forward-looking statements to reflect events or circumstances that may occur
after the date of this prospectus or the effect of those events or circumstances
on any of the forward-looking statements contained herein, except as required by
law.
Results Of Operations
Overview
Margins. We operate on a not-for-profit basis and, accordingly, seek
only to generate revenues sufficient to pay operating and maintenance costs, the
cost of purchased power, capital expenditures, depreciation and principal and
interest on our indebtedness and to provide for the establishment of reasonable
margins and reserves. Patronage capital, the retained margins of our members,
constitutes our principal equity.
Rate Regulation and Rates. Our rates are made up of two components:
"base rates" composed of demand and energy charges; and a "fuel surcharge" that
takes into account the rise and fall of fuel and purchased power costs. The RCA
regulates the rates paid by our wholesale and retail customers under base rates
and approves the quarterly fuel surcharge filing authorizing rate changes in the
fuel surcharge calculations.
Base Rates. We recover operating and maintenance and other non-fuel and
purchased power costs through our base rate established through a general rate
case process or through other normal RCA procedures. While the formal ratemaking
process typically takes nine months to one year, it is within the RCA's
authority to authorize, after a notice period, rate changes on an interim and
refundable basis. In addition, the RCA has been willing to open limited reviews
to resolve specific issues from which expeditious decisions can often be
generated.
Our base rates to our retail customers have not increased since 1994.
Our base rates to our wholesale customers have been subject to periodic
adjustment based on an order from the RCA. We will file a new general rate case
at the end of the second quarter of 2001 that, when adjudicated, may result in a
modest rate increase.
Our annual base rate changes, excluding fuel surcharges, for retail and
wholesale classes, for the years 1998 through 2000 were as follows:
2000 1999 1998
---- ---- ----
Retail 0.00% 0.00% 0.00%
Wholesale:
Homer (0.70%) (0.30%) 0.00%
MEA (0.80%) (3.80%) (0.20%)
Seward 0.00% 0.00% (15.00%)
The rate reductions to Matanuska Electric Association ("MEA") and Homer
result from the operation of a Settlement Agreement dated effective as of
November 21, 1996 as amended, among us, MEA, Homer and AEG&T (the "Settlement
Agreement"). The Settlement Agreement was designed to resolve a number of
ratemaking disputes and assure MEA and Homer that their base rates through 1999
would be no higher than those based on 1995 costs and would be reduced and
refunds given if our 1996, 1997 or 1998 test year costs to serve their needs
were significantly reduced.
The Settlement Agreement has not operated as we intended, because the
RCA has required us to make filings of our cost of service to facilitate
determination of over- or under-collection based on the 1996, 1997 and 1998 test
years. The rate reductions shown in the table for MEA and Homer in 1999 and 2000
relate to the first filing under the Settlement Agreement based on 1996 costs.
Our calculations based on 1996 costs indicated that a rate reduction was
required and that a refund was owed for the previous periods. We recorded
provisions for wholesale rate refunds that totaled $2,651,361 at December 31,
1999. Early in 2000, we issued refunds of $86,132 to Homer and $1,809,801 to MEA
that represented uncontested amounts owed consistent with the 1996 test year
filing.
In June 2000, the RCA issued a final order approving our 1996 test year
cost of service. As a result of this order, we issued additional refunds to MEA
and Homer in the amounts of $332,157 and $503,272, respectively, on July 25,
2000. Consistent with the Settlement Agreement, these refunds were based on
demand and energy purchases retroactive to January 1, 1997.
The rate reduction to Seward in 1998 was the result of a contract
renegotiation through which Seward moved from being a firm customer to an
interruptible customer. The rate reduction reflects the reduced cost of service
to serve Seward since the Seward load can be interrupted.
Fuel Surcharge. Fuel and purchased power costs are passed directly to
our wholesale and retail customers through the fuel surcharge. Changes in these
costs are due to fuel price adjustment mechanisms in our gas supply contracts
based on factors like inflation or other market conditions. We pass these costs
directly to our retail and wholesale customers, resulting in either a direct
increase or decrease to our system revenues. The fuel surcharge is approved on a
quarterly basis by the RCA. There are no limitations on fuel surcharge rate
changes. Increases in our fuel and purchased power costs result in increased
revenues while decreases in these costs result in lower revenues. Therefore,
revenue from the fuel surcharge normally does not impact margins.
The RCA ordered retroactive refunds in the approximate amount of $1.2
million because of alleged overcollection of fuel surcharges in 1995, 1996 and
1997. We appealed that finding to the Superior Court, which overturned the RCA's
ruling. While the RCA did not appeal the decision, our wholesale customer, MEA
did appeal that decision to the Alaska Supreme Court. MEA filed a brief in
support of its claim in January 2001. We filed our brief on March 14, 2001. No
hearing date has been set by the court.
Year ended December 31, 2000 compared to the years ended December 31,
1999 and 1998
Revenues
Operating revenues include sales of electric energy to retail,
wholesale and economy energy customers and other miscellaneous revenues. In
2000, operating revenues were $159 million, or 11%, higher than in 1999
primarily due to increased sales of economy energy to Golden Valley Electric
Association ("GVEA") following the shutdown of the Healy Clean Coal Project (the
"Healy Plant") in February 2000, higher recoverable fuel and purchased power
costs and increased revenue generated by our non-traditional business ventures.
In 1999, operating revenues were $143 million, or 0.57%, higher than in 1998.
Retail base rates for demand and energy did not change in 1999 while base rates
for demand and energy charged to MEA and Homer decreased slightly. Revenues and
power sold were as follows for the years ended December 31:
Year MWH Sold Operating Revenues
2000 2,405,389 $158,541,114
1999 2,190,253 $142,644,327
1998 2,055,963 $141,825,373
We make economy sales to GVEA. These sales commenced in 1988 and have
contributed to our growth in operating revenues. We do not take such economy
sales into consideration in our long-range resource planning process because
these sales are non-firm sales that depend on GVEA's need for additional energy
and our available generating capacity at the time. In 2000, 1999, and 1998,
economy sales to GVEA constituted approximately 5.03%, 0.79%, and 0.92%,
respectively, of our sales revenues. The increase in economy sales in 2000 from
1999 is due primarily to the shutdown of the Healy Plant, increasing the need
for GVEA to make economy purchases. The Healy Plant is a 50 megawatt
demonstration project in Healy, Alaska on the Alaska Intertie between Fairbanks
and Anchorage. Following the test period in 1998, GVEA asserted that the
demonstration was not successful. Litigation ensued and the Healy Plant has been
shutdown since that time pending further analysis of alternatives for its
operation. As a result, GVEA began buying economy energy from us at the time of
the Healy Plant shutdown.
Expenses
The major components of our operating expenses for the years ended
December 31, 2000, 1999 and 1998 were as follows:
2000 1999 1998
---- ---- ----
Power production $ 52,726,374 $ 40,301,607 $ 45,261,450
Purchased power 9,152,248 8,581,979 8,462,835
Transmission 3,828,630 3,813,438 2,771,652
Distribution 9,774,860 9,400,618 8,876,890
Consumer accoun 5,275,455 4,387,421 4,177,980
Sales expense 1,112,804 1,227,908 1,125,410
Administrative, general and
other 21,343,393 22,892,479 17,592,829
Depreciation 23,216,509 19,851,436 22,468,395
---------- ---------- ------------
Total operating expenses $126,430,273 $110,456,886 $110,737,441
Power production expense increased in 2000 from 1999 by $12.4 million,
or 31%, due primarily to an increase in fuel expense from $29.6 million in 1999
to $42.5 million in 2000, which resulted from an average 40% increase in fuel
prices from 1999 to 2000. Power production expense decreased by $4.9 million, or
11%, in 1999 from 1998 due primarily to a decrease in fuel expense.
Purchased power costs increased from 1999 to 2000 by $570,000, or 7%.
We purchased more power from the Soldotna 1 unit and Anchorage Municipal Light
and Power ("AML&P") than anticipated due to avalanche damage to our transmission
lines early in the year, the limited availability of Beluga 3 and Beluga 6 units
during the summer months and an increase in economy energy purchases for GVEA.
Purchased power costs did not vary materially from 1998 to 1999.
Transmission expense did not vary materially from 1999 to 2000.
Transmission expense increased in 1999 from 1998 by $1 million, or 38%, due to
unanticipated transmission line repairs, Y2K preparation and testing and
overhead line maintenance activity as a result of outages early in 1999.
Distribution expense increased in 2000 from 1999 by $374,000, or 4%,
due primarily to an update in allocations of cost related to the information
services and garage clearing. This update shifted those costs from the general
and administrative category to the appropriate functional areas of the company.
Distribution expense increased in 1999 from 1998 by $525,000, or 6%, due
primarily to the increased outage activity that occurred early in 1999, which
resulted in increased labor costs.
Consumer accounts expense increased in 2000 from 1999 by $888,000 or
20%. This was due to less charges to costs for doubtful accounts in 1999 as
compared to 2000. In addition, the update to allocations of cost related to
information services caused an increase to this category in 2000. The increase
in consumer accounts in 1999 from 1998 was not material but resulted from
additional allocated marketing costs offset by less charges to costs for
doubtful accounts in 1999.
Sales expense did not vary materially in 2000, 1999 or 1998. The slight
variances are due to more or less allocated marketing cost resulting from
changes in the number of employees in the marketing department in these years.
Administrative, general and other expense decreased by $1.55 million,
or 6.8%, from 1999 to 2000. This decrease was a result of costs incurred in 1999
for outside counsel, consulting, advertising and internal labor costs associated
with an unsolicited MEA takeover attempt and resultant special meeting in 1999
and an update in allocations of cost related to information services in 2000.
General and administrative expense increased by $5.3 million, or 30%, from 1998
to 1999, primarily due to the costs associated with the MEA takeover attempt, an
increase in software amortization expense, increased maintenance costs of the
Y2K compliant software implementation completed in 1998, additional expenses
associated with our ancillary businesses and multiple insurance settlements paid
in 1999. In addition, general plant maintenance expenses were higher due to
multiple projects completed in 1999.
We use the composite method of depreciation. The increase in
depreciation expense from 1999 to 2000 was $3.4 million, or 17%, and was the
result of more transmission assets being placed in service in 2000. Depreciation
expense decreased in 1999 from 1998 by $2.6 million, or 12%, due to a change in
lives of general plant.
Interest on long term debt increased for the year ended December 31,
2000 over 1999, by $849,000, or 4%, due to higher amounts of outstanding debt.
Our outstanding indebtedness increased due to the issuance of $30 million in
bonds to CoBank, ACB ("CoBank") and to increased borrowing under the lines of
credit with CoBank and the National Rural Utilities Cooperative Finance
Corporation ("CFC") to fund the Beluga 6 re-powering project and the Cooper Lake
facility overhaul. Interest on short-term debt increased from 1999 to 2000 by
$912,000, or 91%, because of higher balances maintained and higher interest
rates. Our weighted average cost of total borrowings for 2000 was 8.06% compared
to 8.14% for 1999. Interest on long-term debt was slightly lower in 1999 than
1998 by $1 million, or 4%, due primarily to the refinancing of $34.9 million of
Series A Bonds due 2022 in the first quarter of 1999. Our weighted average cost
of total borrowings for 1998 was 8.43%. Net interest expense includes interest
on long-term debt and short-term debt, reduced by interest charged to
construction. Net interest expense is reduced by $1.54 million, $1.09 million
and $1.44 million in 1998, 1999 and 2000, respectively, which represents the net
effect of the amortization of the gain on refinancing offset by the amortization
of losses on refinancing and transaction costs.
Margins
Our margins for the years ended December 31, 2000, 1999 and 1998, were
as follows:
Net Operating Margins Nonoperating Margins Assignable Margins
2000 $ 7,392,551 $ 2,287,227 $ 9,679,778
1999 $ 8,052,060 $ 1,615,374 $ 9,667,434
1998 $ 6,619,263 $ 2,111,141 $ 8,730,404
Nonoperating margins include interest income, allowance for funds used
during construction, capital credits and patronage capital allocations.
Nonoperating margins increased in 2000 over 1999 by $672,000 or 42%. This was
due to an allowance for funds used during construction based on higher
construction work in progress balances during the year, increased allocations of
patronage capital from CoBank, and higher interest earnings in 2000 as a result
of increased short-term investment balances. Nonoperating margins decreased in
1999 over 1998, by $496,000, or 23%. The primary contributor to the decrease
from 1998 is the gain on the sale of a surplus compressor rotor to GVEA in 1998.
The variance is also due in part to higher-than-anticipated patronage capital
from CoBank but is offset by a decrease in interest earnings in 1999 as a result
of decreased short-term investment balances.
Patronage Capital (Equity)
Our patronage capital and total equity have shown steady growth. The
following table summarizes our patronage capital and total equity position since
1998:
2000 1999 1998
---- ---- ----
Patronage capital at beginning
of year $117,335,481 $109,622,996 $104,800,092
Retirement of capital credits
and estate payments (4,090,006) (1,954,949) (3,907,500)
Assignable margins 9,679,778 9,667,434 8,730,404
------------ ------------ ------------
Patronage capital at end of year 122,925,253 117,335,481 109,622,996
Other equity 5,890,087 5,189,164 4,400,300
----------- ------------ ------------
Total equity at end of year $128,815,340 $122,524,645 $114,023,296
============ ============ ============
In furtherance of our operations as a cooperative, we credit to our
members all amounts received from them for the furnishing of electricity in
excess of our operating costs, expenses and provision for reasonable reserves.
These excess amounts (i.e., assignable margins) are considered capital furnished
by the members, and are credited to their accounts and held by us until such
future time as they are retired and returned without interest. Approval of
actual capital credit retirements is at the discretion of our Board of
Directors. We currently have a practice of retiring patronage capital on a
first-in, first-out basis for retail customers. At December 31, 2000, we retired
all retail capital credits attributable to margins earned in periods prior to
1984 and approximately 19% of 1985 retail capital credits. Prior to 2000,
wholesale capital credits had been retired on a 10-year cycle pursuant to an
Equity Management Plan Settlement Agreement despite its expiration in 1995.
However, in 2000, there was no wholesale retirement as we implemented a plan to
return the capital credits of wholesale and retail customers on a 15-year
rotation.
The 1991 Indenture includes a covenant restricting the distribution of
patronage capital to members. We cannot distribute patronage capital to members
if 1) an event of default exists or 2) the aggregate amount of patronage capital
distributions after September 15, 1991, exceeds the sum of $7,000,000 plus 35%
of the aggregate assignable margins earned after December 31, 1990. At December
31, 2000, we were permitted to distribute $4.14 million to our members under the
1991 Indenture under this formula.
We also retire our patronage credits through annual payments to our
members. The table below sets forth a five-year summary of anticipated capital
credit retirements:
Year Ending Wholesale Retail Total
2001 $ 0 $3,500,000 $3,500,000
2002 0 3,500,000 3,500,000
2003 0 3,500,000 3,500,000
2004 1,359,000 3,500,000 4,859,000
2005 1,109,000 3,500,000 4,609,000
Times Interest Earned Ratio (TIER)
Alaska electric cooperatives generally set rates on the basis of TIER.
TIER is determined by dividing the sum of assignable margins plus long-term
interest expense (excluding capitalized interest) by long-term interest expense.
Beginning in 1989, our Board of Directors approved an Equity Management Plan
that established a schedule for building our equity. Since then we have managed
our business with a view toward achieving a TIER of 1.25 or greater. We achieved
TIERs for the past five years as follows:
Period TIER
2000 1.39
1999 1.40
1998 1.35
1997 1.30
1996 1.39
Sale of a Segment
As of March 20, 2001, we sold to GCI Communication Corporation the bulk
of our internet service provider assets related to dial-up services (excluding
DSL services). The aggregate purchase price was $759,049 at closing, with a
potential for additional amounts, not to exceed $85,850, based on the number of
subscriber accounts retained during the ninety-day transition period following
closing. We are also to receive service fees for technical and other transition
services during such period billed on a time-and-materials basis. The
transaction will result in a minimal gain.
Changes In Financial Condition
Total assets increased by $21.4 million, or 4%, from December 31, 1999,
to December 31, 2000. The increase was due to an increase in electric plant in
service related to the Beluga 6 unit re-powering, the U.S. Postal Service fuel
cell project and various distribution projects. This, however, was offset by a
decrease in cash and cash equivalents caused by the funding requirements imposed
by the above-mentioned projects and a decrease in materials and supplies caused
by the writing off of spare generation parts from inventory. There was an
increase in accounts receivable caused by the under-collection of the fuel
surcharge in the fourth quarter of 2000. Changes to total liabilities include
the increase in notes payable due to borrowing activity during the year. There
was also an increase in accrued salaries, wages and benefits due to overall
increases in company-wide benefits, as well as increases associated with new
contracts with the IBEW. Additionally, the fuel liability increased due to
rising fuel prices.
Liquidity And Capital Resources
We satisfy our operational and capital cash requirements primarily
through internally-generated funds, a $50 million line of credit from CFC and a
$35 million line of credit with CoBank. At December 31, 2000, there was $5
million outstanding with CFC. An additional $5 million was borrowed in January
2001, and an additional $10 million was borrowed in March 2001. The current
outstanding balance as of March 2001 is $20 million. This line of credit bears
interest at a variable rate, which was 8.550% as of December 31, 2000, and is
currently 8.050% as of March 2001. As of December 31, 2000, $35 million was
outstanding under the CoBank line of credit. This line of credit bears interest
at a variable rate, which was 8.20% as of December 31, 2000, and is currently
7.70% as of March 2001. Additionally, we have negotiated a supplemental
indenture with CFC authorizing a series of bonds in an amount of up to $80
million. At December 31, 2000, we had issued no bonds to CFC.
On March 22, 2001, Chugach filed a Registration Statement, Form S-1,
with the Securities and Exchange Commission in anticipation of Chugach's $150
million public bond offering.
Principal maturities and sinking fund payments of our outstanding
indebtedness at December 31, 2000 are set forth below:
Year Ending
December 31 Sinking Fund Requirements Principal maturities Total
----------- ------------------------- -------------------- -----
2001 $ 6,097,000 $ 333,350 $ 6,430,350
2002 5,232,000 77,677,944 82,909,944
2003 5,041,000 865,821 5,906,821
2004 5,502,000 945,000 6,447,000
2005 6,005,000 11,031,000 17,036,000
Thereafter 147,762,000 52,158,180 199,920,180
During 2000, we spent approximately $46.7 million on capital
construction projects, which includes interest capitalized during construction.
We develop five-year work plans that are updated every year. Our capital
improvement requirements are based on long-range plans and other supporting
studies and are executed through a five-year construction work plan. Set forth
below is an estimate of capital expenditures for the years 2001 through 2005:
2001 $36.0 million
2002 $42.5 million
2003 $40.2 million
2004 $40.0 million
2005 $40.1 million
We are a party to a Treasury rate-lock with respect to the refinancing
of a portion of the 1991 Series A Bonds. The settlement date of this contract is
March 15, 2002. At December 31, 2000, the Treasury-rate lock agreement had an
estimated value of ($8.6) million. At March 29, 2001, the agreement had an
estimated value of ($10.37) million. See "Quantitative and Qualitative
Disclosures About Market Risk--Interest Rate Risk."
We expect that cash flows from operations and external funding sources
will be sufficient to cover operational and capital funding requirements in 2001
and thereafter.
Changes in Accounting Principles
We were required to adopt SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS No. 138, effective
January 1, 2001. This new standard requires all derivative financial instruments
to be reflected on the balance sheet. As of January 1, 2001, we have established
a regulatory asset for $8.6 million and a liability for the same amount. The
regulatory asset and liability will be adjusted for changes in the fair value of
a Treasury rate-lock agreement entered into by us. See "Quantitative and
Qualitative Disclosures about Market Risk - Interest Rate Risk." Management
believes it is probable the regulatory asset will be recovered through rates.
Item 7A - Quantitative and Qualitative Disclosures
About Market Risk
We are exposed to a variety of risks, including changes in interest
rates and changes in commodity prices due to repricing mechanisms inherent in
gas supply contracts. In the normal course of our business, we manage our
exposure to these risks as described below. We do not engage in trading market
risk-sensitive instruments for speculative purposes.
Interest Rate Risk
As of December 31, 2000, except for two bonds issued to CoBank carrying
variable interest rates that are periodically re-priced, all of our other
outstanding long-term borrowings were at fixed interest rates with varying
maturity dates. The following table provides information regarding cash flows
for principal payments on total debt by maturity date (dollars in thousands) as
of December 31, 2000 and 1999:
2000
Fair
Total Debt* 2001 2002 2003 2004 2005 Thereafter Total Value
- ----------- ---- ---- ---- ---- ---- ---------- ----- -----
Fixed rate $6,430 $10,410 $5,907 $6,447 $17,036 $199,920 $246,150 $262,655
Average
interest rate 8.13% 6.90% 8.62% 8.62% 8.12% 8.22% 8.17%
Variable rate $40,000 $72,500 $0 $0 $0 $0 $112,500 $112,500
Average
interest rate 8.24% 8.20% -- -- -- -- 8.22%
* Includes current portion
1999
Fair
Total Debt* 2000 2001 2002 2003 2004 Thereafter Total Value
- ----------- ---- ---- ---- ---- ---- ---------- ----- -----
Fixed rate $6,372 $6,430 $10,410 $5,907 $6,447 $235,456 $271,023 $282,034
Average
interest rate 8.12% 8.13% 6.90% 8.62% 8.62% 7.95% 7.95%
Variable rate $0 $0 $72,500 $0 $0 $0 $72,500 $72,500
Average
interest rate -- -- 6.87% -- -- -- 6.87%
* Includes current portion
We are exposed to market risk from changes in interest rates. A 100
basis-point change (up or down) would increase or decrease our interest expense
by approximately $1,125,000, based on $112.5 million of variable debt
outstanding at December 31, 2000. The CoBank and CFC lines of credit, under
which we currently have $40 million in short-term debt outstanding, bear
interest at variable rates.
As of December 31, 2000, the aggregate principal amount of outstanding
1991 Series A Bonds due 2022 was $164,310,000. The 1991 Series A Bonds due 2022
are not callable until March 15, 2002. To manage interest rate exposure for
refinancing of these bonds on their first available call date, March 15, 2002,
we entered into a Treasury rate-lock transaction with Lehman Brothers Financial
Products Inc. ("Lehman Brothers"). Under the Treasury rate-lock contract, we
will receive a lump-sum payment from Lehman Brothers on March 15, 2002, if the
yield on 10- or 30-year Treasury bonds as of mid-February 2002, exceeds a
specified target level (5.653% and 5.838%, respectively). Conversely, we will on
the same date be required to make a payment to Lehman Brothers if the yield on
the 10- or 30-year Treasury bonds falls below their stated target yields. In
each case, the amount of the payment will increase as the difference between the
actual yield and the target yield widens. For each basis point (0.01% per annum)
by which the yield on 10-year or 30-year Treasury bonds deviates from the stated
target level we will receive (if the prevailing Treasury yield exceeds the
target yield) or make (if the prevailing Treasury yield falls short of the
target yield) a payment equal to the product obtained by multiplying (i) the
difference between the prevailing and target yields (expressed in basis points)
by (ii) the changes in the prices of $196 million (in the case of 10-year
Treasury bonds) and $18.7 million (in the case of the 30-year Treasury bonds) of
Treasury bonds, given a one-basis-point change in their respective yields
(determined with reference to the Bloomberg Financial Markets Government Yield
Analysis Page). In this way, we intend that higher interest costs resulting from
any increases in market interest rates between the date of the rate-lock
contract and the refinancing of our long-term debt would be mitigated by a
lump-sum, up-front payment to us at the time of the refinancing. Conversely, any
savings from decreases in interest rates during the same period would be reduced
by a payment by us to the rate-lock counterparty. At December 31, 2000 and 1999,
the Treasury rate lock agreement had an estimated value of approximately
$(8,600,000) and $13,000,000, respectively. The decrease in estimated value is
due to the decline on the yield on the 10-year and 30-year Treasury bonds. A 10
basis-point change (up or down) in the prevailing yield on both 10-year and
30-year Treasury bonds would change the value of the rate-lock agreement (up or
down) by approximately $1,800,000.
Commodity Price Risk
Our gas contracts provide for adjustments to gas prices based on
fluctuations of certain commodity prices and indices. Because purchased power
costs are passed directly to our wholesale and retail customers through a fuel
surcharge, fluctuations in the price paid for gas pursuant to long-term gas
supply contracts does not normally impact margins. The fuel surcharge mechanism
mitigates the commodity price risk related to market fluctuations in the price
of purchased power.
Item 8 -Financial Statements and Supplementary Data
December 31, 2000 and 1999
Independent Auditors' Report
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association,
Inc. as of December 31, 2000 and 1999, and the related statements of revenues,
expenses and patronage capital and cash flows for each of the years in the
three-year period ended December 31, 2000. In connection with our audits of the
financial statements, we have also audited the financial statement schedule
listed in Item 14 herein. These financial statements and financial statement
schedule are the responsibility of the Association's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Chugach Electric Association,
Inc. as of December 31, 2000 and 1999, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2000, in conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly, in all material respects, the information set forth
therein.
/s/ KPMG LLP
Anchorage, Alaska
February 23, 2001, except as to note 17,
which is as of March 6, 2001
CHUGACH ELECTRIC ASSOCIATION, INC.
Balance Sheets
December 31, 2000 and 1999
Assets 2000 1999
------ ---- ----
Utility plant (notes 2, 6, 13 and 14):
Electric plant in service $687,127,130 $ 641,627,328
Construction work in progress 42,027,617 47,257,296
---------- ----------
729,154,747 688,884,624
Less accumulated depreciation 259,999,872 243,082,832
----------- -----------
Net utility plant 469,154,875 445,801,792
----------- -----------
Other property and investments, at cost:
Nonutility property 443,555 413,515
Investments in associated organizations
(note 3) 9,857,153 8,946,861
--------- ---------
10,300,708 9,360,376
---------- ---------
Current assets:
Cash and cash equivalents,including
repurchase agreementsof $3,905,283 in
2000 and $6,574,457 in 1999 1,695,162 4,110,030
Cash-restricted construction funds 378,848 538,404
Special deposits 212,163 182,164
Accounts receivable, less provision for
doubtful accounts of $441,933 in 2000
and $389,223 in 1999 19,200,912 17,730,994
Fuel cost recovery 2,915,733 180,755
Materials and supplies 15,357,198 17,180,136
Prepayments 755,276 861,947
Other current assets 332,246 341,702
-------------- --------------
Total current assets 40,847,538 41,126,132
------------ ------------
Deferred charges (notes 9 and 15) 19,442,859 22,067,237
------------ ------------
$ 539,745,980 $ 518,355,537
=========== =============
See accompanying notes to financial statements.
CHUGACH ELECTRIC ASSOCIATION, INC.
Balance Sheets, Continued
December 31, 2000 and 1999
Liabilities 2000 1999
----------- ---- ----
Equities and margins (note 11):
Memberships $ 1,009,663 $ 960,808
Patronage capital (note 4) 122,925,253 117,335,481
Other (note 5) 4,880,424 4,228,356
--------- ------------
128,815,340 122,524,645
----------- ------------
Long-term obligations, excluding current installments
(notes 6, 7 and 11):
First mortgage bonds payable 169,542,000 194,139,000
National Bank for Cooperatives bonds
Payable 142,677,945 143,011,295
----------- -------------
312,219,945 337,150,295
----------- ------------
Current liabilities:
Current installments of long-term obligations
(notes 6, 7 and 11) 6,430,350 6,372,405
Short-term borrowings (note 6) 40,000,000 0
Accounts payable 9,493,875 9,508,851
Consumer deposits 1,324,213 1,059,677
Accrued interest 5,861,390 6,066,114
Salaries, wages and benefits 4,586,407 4,053,228
Fuel 8,154,559 4,381,304
Other 1,434,562 2,527,798
--------- ------------
Total current liabilities 77,285,356 33,969,377
---------- ------------
Deferred credits (note 12) 21,425,339 24,711,220
---------- ------------
$539,745,980 $518,355,537
============ ============
See accompanying notes to financial statements.
CHUGACH ELECTRIC ASSOCIATION, INC.
Statements of Revenues, Expenses and Patronage Capital
Years ended December 31, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Operating revenues $158,541,114 $ 142,644,327 $ 141,825,373
----------- ------------ ------------
Operating expenses:
Production 52,726,374 40,301,607 45,261,450
Purchased power 9,152,248 8,581,979 8,462,835
Transmission 3,828,630 3,813,438 2,771,652
Distribution 9,774,860 9,400,618 8,876,890
Consumer accounts 5,275,455 4,387,421 4,177,980
Sales expense 1,112,804 1,227,908 1,125,410
Administrative, general and other 21,343,393 22,892,479 17,592,829
Depreciation 23,216,509 19,851,436 22,468,395
----------- ------------ ------------
Total operating expenses 126,430,273 110,456,886 110,737,441
------------ ------------ ------------
Interest:
On long-term debt 24,987,033 24,137,593 25,159,660
Charged to construction - credit (2,178,425) (1,000,246) (821,137)
On short-term debt 1,909,682 998,034 130,146
---------- ------------ ------------
Net interest 24,718,290 24,135,381 24,468,669
----------- ------------ ------------
Net operating margins 7,392,551 8,052,060 6,619,263
Nonoperating margins:
Interest income 703,807 592,208 711,155
Other 1,615,161 1,003,029 1,050,899
Property gain (loss) (31,741) 20,137 349,087
--------- ----------- ------------
Assignable margins 9,679,778 9,667,434 8,730,404
Patronage capital at beginning of year 117,335,481 109,622,996 104,800,092
Retirement of capital credits and
Estate payments (note 4) (4,090,006) (1,954,949) (3,907,500)
---------- ----------- ------------
Patronage capital at end of year $122,925,253 $117,335,481 $109,622,996
============ ============ ============
See accompanying notes to financial statements.
CHUGACH ELECTRIC ASSOCIATION, INC.
Statements of Cash Flows
Years ended December 31, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Cash flows from operating activities:
Assignable margins $9,679,778 $9,667,434 $8,730,404
Adjustments to reconcile assignable margins to net cash
provided by operating activities:
Depreciation and amortization 27,575,408 23,563,805 24,605,760
Capitalization of equity allowance (340,838) (151,474) (260,258)
Property (gains) losses and obsolete inventory write-off (25,425) 242 (349,087)
Other (1,155) (221) 60,734
Changes in assets and liabilities:
(Increase) decrease in assets:
Special deposits (29,999) (61,000) 30,540
Accounts receivable (1,469,918) (1,049,512) 2,549,024
Fuel cost recovery (2,734,978) 381,029 4,206,848
Prepayments 106,671 55,434 (359,010)
Materials and supplies, net 1,822,938 (1,216,702) (344,349)
Deferred charges (1,231,531) (14,179,418) (7,898,240)
Other assets 9,456 7,328 (43,615)
Increase (decrease) in liabilities:
Accounts payable (14,976) 670,093 1,800,524
Accrued interest (204,724) (656,211) (182,010)
Deferred credits (3,638,491) (2,973,944) (1,829,112)
Consumer deposits, net 264,536 66,061 (44,625)
Other liabilities 3,213,198 524,833 (3,129,329)
--------- ------------ -----------
Total adjustments 23,300,172 4,980,343 18,813,795
---------- ----------- ----------
Net cash provided by operating activities 32,979,950 14,647,777 27,544,199
---------- ---------- ----------
Cash flows from investing activities:
Extension and replacement of plant (46,736,359) (41,864,828) (20,269,038)
Increase in investments in associated organizations (909,137) (590,276) (552,827)
------------ ------------ ------------
Net cash (used) in investing activities (47,645,496) (42,455,104) (20,821,865)
------------ ------------ ------------
Cash flows from financing activities:
Transfer of restricted construction funds 159,556 (361,038) 187,412
Proceeds from short-term borrowings 40,000,000 0 0
Proceeds from long-term debt 0 72,500,000 0
Repayments of long-term debt (24,872,405) (40,983,801) (5,913,512)
Memberships and donations received 700,923 788,865 80,695
Retirement of patronage capital (4,090,006) (1,954,949) (3,907,500)
Net receipts (refunds) of consumer advances for construction 352,610 (384,294) (81,384)
--------- ---------- -----------
Net cash provided by (used in) financing activities 12,250,678 29,604,783 (9,634,289)
---------- ---------- -----------
Net change in cash and cash equivalents (2,414,868) 1,797,456 (2,911,955)
Cash and cash equivalents at beginning of year $4,110,030 $ 2,312,574 $ 5,224,529
- ---------------------------------------------- ---------- ----------- -----------
Cash and cash equivalents at end of year $1,695,162 $ 4,110,030 $ 2,312,574
- ---------------------------------------- ========== =========== ===========
Supplemental disclosure of cash flow information - interest
expense paid, net of amounts capitalized 24,917,014 24,791,592 24,650,680
========== ========== ==========
See accompanying notes to financial statements.
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
December 31, 2000 and 1999
(1) Description of Business and Summary of Significant Accounting Policies
Description of Business
Chugach Electric Association, Inc. (Association or Chugach) is the
largest electric utility in Alaska. The Association is engaged in the
generation, transmission and distribution of electricity to directly
served retail customers in the Anchorage and upper Kenai Peninsula areas.
Through an interconnected regional electrical system, Chugach's power
flows throughout Alaska's Railbelt, a 400-mile-long area stretching from
the coastline of the southern Kenai Peninsula to the interior of the
state, including Alaska's largest cities, Anchorage and Fairbanks.
Chugach also supplies much of the power requirements of three wholesale
customers, Matanuska Electric Association (MEA), Homer Electric
Association (Homer) and the City of Seward (Seward).
The Association operates on a not-for-profit basis and, accordingly,
seeks only to generate revenues sufficient to pay operating and
maintenance costs, the cost of purchased power, capital expenditures,
depreciation, and principal and interest on all indebtedness and to
provide for reasonable margins and reserves. The Association is subject
to the regulatory authority of the Regulatory Commission of Alaska (RCA),
(formerly the Alaska Public Utilities Commission (APUC)).
Management Estimates
In preparing the financial statements, management of the Association is
required to make estimates and assumptions relating to the reporting of
assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the balance sheet and revenues and expenses
for the reporting period. Actual results could differ from those
estimates.
Regulation
The accounting records of the Association conform to the Uniform System
of Accounts as prescribed by the Federal Energy Regulatory Commission.
The Association meets the criteria, and accordingly, follows the
accounting and reporting requirements of Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types
of Regulation (SFAS 71). Revenues in excess of current period costs (net
operating margins and nonoperating margins) in any year are designated on
the Association's statement of revenues and expenses as assignable
margins. Retained assignable margins are designated on the Association's
balance sheet as patronage capital, which is assigned to each member on
the basis of patronage. This patronage capital constitutes the principal
equity of the Association.
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
Reclassifications
Certain reclassifications have been made to the 1998 and 1999 financial
statements to conform to the 2000 presentation.
Plant Additions and Retirements
Additions to electric plant in service are recorded at original cost of
contracted services, direct labor and materials, and indirect overhead
charges. For property replaced or retired, the average unit cost of the
property unit, plus removal cost, less salvage, is charged to accumulated
provision for depreciation. The cost of replacement is added to electric
plant.
Operating Revenues
Operating revenues are based on billing rates authorized by the RCA which
are applied to customers' usage of electricity. Included in operating
revenue are billings rendered to customers adjusted for differences in
meter read dates from year to year. The Association's tariffs include
provisions for the flow through of gas costs pursuant to existing gas
supply contracts.
Chugach entered into a settlement agreement with MEA and Homer in 1996.
The settlement agreement was designed to resolved a number of ratemaking
disputes and assure MEA and Homer that their base rates would be no
higher than those based on 1995 costs and would be reduced (and refunds
given) if our 1996, 1997 or 1998 test year costs to serve their needs
were significantly reduced. The RCA has required Chugach to make filings
of Chugach's cost of service to facilitate determination of any refunds
owed under the settlement agreement.
Calculations based on 1996 costs indicated that a rate reduction was
required and that a refund was owed for the previous periods. Chugach
recorded provisions for wholesale rate refunds that totaled $2,651,361 as
of December 31, 1999. Early in 2000, refunds of $86,132 were issued to
Homer and $1,809,801 to MEA that represented uncontested amounts owed
consistent with the 1996 test year filing.
In June 2000, the RCA issued its final order approving the 1996 test year
cost of service. As a result of this order, additional refunds were
issued to MEA and Homer in the amounts of $332,157 and $503,272,
respectively, on July 25, 2000. Consistent with the Settlement Agreement,
these refunds were based on demand and energy purchases retroactive to
January 1, 1997.
The process for RCA, MEA and Homer review of 1997 test year costs is
nearly complete. An order from the RCA was received February 27, 2001,
and no rate reduction or refunds were required. Both MEA and Chugach have
filed petitions for reconsideration of this order.
The 1998 test year cost calculation is currently being reviewed by the
RCA. Management believes that no rate reduction or refund will be
required based on the 1998 test year.
The RCA has required that Chugach file a general rate case based on the
2000 test year by June 30, 2001. This filing may request a modest
increase in base rates.
In 1998 a power sales agreement was negotiated between Chugach and
Seward. The contract was approved by the RCA on June 14, 1999 for a
three-year term, which expires on September 1, 2001. The parties have
recently negotiated and executed an Amendment, extending the term of the
contract to January 31, 2006, subject to approval by the RCA.
In October 1998 Marathon Oil Company, one of Chugach's natural gas
suppliers, notified Chugach that it had reached a settlement with the
State of Alaska regarding additional excise and royalty taxes for the
period 1989 through 1998. In accordance with the purchase contract,
Chugach would be responsible for these additional taxes. The RCA approved
Chugach's plan to recover this over 12 months through the Fuel Surcharge
mechanism except for the retail portion in the amount of $436,778 that
was written-off at December 31, 1998. Recovery of this expense in rates
continued from April 1, 1999 through April 1, 2000. Despite RCA approval
and subsequent re-confirmation by the RCA, MEA has refused to pay the
portion of its monthly bill it considers to be recovery of the Marathon
tax. Effective December 20, 2000, by the Superior Court for the State of
Alaska, MEA was ordered to pay $298,004, representing the unpaid tax
liability and associated litigation costs. MEA has appealed this order to
the Alaska Supreme Court.
Investments in Associated Organizations
Investments in associated organizations represent capital requirements as
part of financing arrangements. These investments are non-marketable and
accounted for at cost.
Deferred Charges and Credits
Deferred charges, representing regulatory assets, are amortized to
operating expense over the period allowed for rate-making purposes,
generally five years.
Nonrefundable contributions in aid of construction are credited to the
associated cost of construction of property units. Refundable
contributions in aid of construction are held in deferred credits pending
their return or other disposition.
Depreciation and Amortization
Depreciation and amortization rates have been applied on a straight-line
basis and at December 31, 2000 are as follows:
Rate (%)
Steam production plant 2.70 - 2.96
Hydraulic production plant 1.33 - 2.88
Other production plant 3.34 - 6.50
Transmission plant 1.85 - 5.37
Distribution plant 2.10 - 4.55
General plant 2.22 - 20.00
Other 1.88 - 2.75
In 1997 an update of the Depreciation Study was completed utilizing
Electric Plant in Service balances as of December 31, 1995. Depreciation
rates developed in that study were implemented in January, 1998. In 2000
another update of the study was completed. Depreciation rates determined
in that study will be implemented upon approval by the RCA.
Capitalized Interest
Allowance for funds used during construction and interest charged to
construction - credit are the estimated costs during the period of
construction of equity and borrowed funds used for construction purposes.
The Association capitalized such funds at the average rate (adjusted
monthly) of 7.9% during 2000, 7.4% during 1999 and 8.3% during 1998.
Cash and Cash Equivalents
For purposes of the statement of cash flows, the Association considers
all highly liquid debt instruments with a maturity of three months or
less upon acquisition by the Association (excluding restricted cash and
investments) to be cash equivalents.
Materials and Supplies
Materials and supplies are stated at the lower of cost or market and
valued at average cost.
Fair Value of Financial Instruments
Statement of Financial Accounting Standards 107, Disclosures About the
Fair Value of Financial Instruments, requires disclosure of the fair
value of certain on and off balance sheet financial instruments for which
it is practicable to estimate that value. The following methods are used
to estimate the fair value of financial instruments:
Cash and cash equivalents and restricted cash - the carrying amount
approximates fair value because of the short maturity of those
instruments.
Investments in associated organizations - the carrying amount
approximates fair value because of limited marketability and the nature
of the investments.
Consumer deposits - the carrying amount approximates fair value because
of the short refunding term.
Long-term obligations - the fair value is estimated based on the quoted
market price for same or similar issues (note 7).
Forward rate lock agreements - the fair value is estimated based on
discounted cash flow using current rates.
Financial Instruments and Hedging
The Association uses U.S. Treasury forward rate lock agreements to hedge
expected interest rates on probable debt refinancings. Under the
guidance of SFAS No. 80, Accounting for Futures Contracts, the
Association has accounted for the treasury rate lock agreement as a
hedge. Accordingly, the unrealized gain or loss has not been recorded
and will be treated as a regulatory asset or liability upon settlement
(note 6).
Income Taxes
The Association is exempt from federal income taxes under the
provisions of Section 501(c)(12) of the Internal Revenue Code,
except for unrelated business income. For the years ended December 31,
2000, 1999 and 1998 the Association received no unrelated business
income.
Environmental Remediation Costs
The Association accrues for losses associated with environmental
remediation obligations when such losses are probable and can be
reasonably estimated. Such accruals are adjusted as further information
develops or circumstances change. Estimates of future costs for
environmental remediation obligations are not discounted to their present
value.
2) Utility Plant Summary
Major classes of electric plant as of December 31 are as follows:
2000 1999
---- ----
Electric plant in service:
Steam production plant $60,392,869 $60,392,869
Hydraulic production plant 8,798,695 8,798,695
Other production plant 106,017,802 104,925,446
Transmission plant 211,860,829 211,881,174
Distribution plant 170,378,081 162,365,836
General plant 45,835,618 47,704,821
Unclassified electric plant in service 77,054,390 38,834,298
Equipment under capital lease 56,323 56,323
Other 6,732,523 6,667,866
------------- -------------
Total electric plant in service 687,127,130 641,627,328
Construction work in progress 42,027,617 47,257,296
------------- ------------
Total electric plant in service
and construction work in progress $729,154,747 $688,884,624
============ ============
Depreciation of unclassified electric plant in service has been included
in functional plant depreciation accounts in accordance with the
anticipated eventual classification of the plant investment.
(3) Investments in Associated Organizations
Investments in associated organizations include the following at December
31:
2000 1999
---- ----
National Rural Utilities Cooperative Finance
Corporation (NRUCFC) $ 6,095,980 $ 6,095,980
National Bank for Cooperatives (CoBank) 3,600,133 2,708,200
NRUCFC capital term certificates 33,733 32,300
Other 127,307 110,381
------- ---------
$9,857,153 $8,946,861
========== ==========
The Farm Credit Administration, CoBank's federal regulators, requires
minimum capital adequacy standards for all Farm Credit System
institutions. CoBank's loan agreements require, as a condition of the
extension of credit, that an equity ownership position be established by
all borrowers. The Association's investment in NRUCFC similarly was
required by its financing arrangements with NRUCFC.
(4) Patronage Capital
The Association has an approved Equity Management Plan which establishes
in general, a ten-year (for wholesale customers) and twenty-year (for
retail customers) capital credit retirement of patronage capital, based
on the members' proportionate contribution to Association assignable
margins. On January 19, 2000, the Board of Directors passed a resolution
putting all members on a 15-year rotation. At December 31, 2000, out of
the total of $122,925,253 patronage capital, the Association had
assigned $89,432,752 of such patronage capital (net of capital credit
retirements). Approval of actual capital credit retirements is at the
discretion of the Association's Board of Directors.
In December 1998 the Board of Directors authorized the retirement of
$2,208,997 of retail capital credits representing the balance of 1984
retail distribution patronage. The Board also authorized the retirement
of $1,533,287 of wholesale patronage for 1988.
In November 1999 the Board of Directors authorized the retirement of
$1,766,000 of retail patronage for 1984.
In November 2000 the Board of Directors authorized the retirement of
$3,750,000 of retail patronage for 1984 and 1985.
Following is a five-year summary of anticipated capital credit
retirements:
Year ending Wholesale Retail Total
----------- --------- ------ -----
2001 $ - $3,500,00 $3,500,000
2002 - 3,500,00 3,500,000
2003 - 3,500,00 3,500,000
2004 1,359,000 3,500,00 4,859,000
2005 1,109,000 3,500,00 4,609,000
(5) Other Equities
A summary of other equities at December 31 follows:
2000 1999
---- ----
Nonoperating margins, prior to 1967 $ 23,625 $ 23,625
Donated capital 183,907 183,907
Unredeemed capital credit retirement 4,672,892 4,020,824
----------- ----------
$4,880,424 $4,228,356
========== ==========
(6) Debt
Long-term obligations at December 31 are as follows:
2000 1999
---- ----
First mortgage bonds of 8.08% maturing in 2002 and 9.14% maturing in 2022
with interest payable semiannually March 15 and September 15:
8.08% $ 11,329,000 $ 17,396,000
9.14% 164,310,000 182,810,000
CoBank 8.95% bond maturing in 2002,
With interest payable monthly and
Principal due semi-annually 511,295 816,700
CoBank 7.76% bond maturing in 2005,
With interest payable monthly 10,000,000 10,000,000
CoBank 5.60% bonds maturing in 2022, with
Interest payable monthly 45,000,000 45,000,000
CoBank 5.60% bonds maturing in 2002,
2007 and 2012 with interest payable
monthly 15,000,000 15,000,000
CoBank, variable interest, with a rate of 8.20% at
December 31, 2000, bonds maturing in 2002, with 42,500,000 42,500,000
interest payable monthly
CoBank, variable interest, with a rate of 8.20% at
December 31, 2000, bonds maturing in 2002, with 30,000,000 30,000,000
interest payable monthly ----------- ----------
Total long-term obligations 318,650,295 343,522,700
Less current installments 6,430,350 6,372,405
--------------- -------------
Long-term obligations, excluding
current installments $ 312,219,945 $337,150,295
============= ============
Substantially all assets are pledged as collateral for the long-term
obligations.
Maturities of Long-term Obligations
Long-term obligations at December 31, 2000 mature as follows:
Year ending Sinking Fund Requirements Principal maturities Total
-------------------- -----
December 31
First mortgage CoBank
Bonds Mortgage bonds
2001 $6,097,000 $333,350 $6,430,350
2002 5,232,000 77,677,944 82,909,944
2003 5,041,000 865,821 5,906,821
2004 5,502,000 945,000 6,447,000
2005 6,005,000 11,031,000 17,036,000
Thereafter 147,762,000 52,158,180 199,920,180
-------------- ------------- -----------
$175,639,000 $143,011,295 $318,650,295
============= ============ ============
Lines of Credit
The Association had an annual line of credit of $35,000,000 in 2000 and
1999 available with CoBank. The CoBank line of credit expires August 1,
2001 but carries an annual automatic renewal clause. At December 31, 2000
there was $35 million outstanding on this line of credit which carried an
interest rate of 8.20%. At December 31, 1999 there was no outstanding
balance. In addition, the Association had an annual line of credit of
$50,000,000 available at December 31, 2000 and 1999 with NRUCFC. At
December 31, 2000 there was $5 million outstanding on this line of credit
which carried an interest rate of 8.55%. At December 31, 1999 there was
no outstanding balance. The NRUCFC line of credit expires October 14,
2002.
Refinancing
On September 19, 1991, Chugach issued $314,000,000 of First Mortgage
Bonds, 1991 Series A (Bonds), for purposes of repaying existing debt to
the Federal Financing Bank and the Rural Electrification Administration
(now Rural Utilities Services). Pursuant to Section 311 of the Rural
Electrification Act, Chugach was permitted to prepay the REA debt at a
discounted rate of approximately 9%, resulting in a discount of
approximately $45,000,000 (note 12).
The bonds maturing in 2002 (Series A 2002 Bonds) are subject to annual
sinking fund redemption at 100% of the principal amount thereof which
commenced March 15, 1993. The bonds maturing in 2022 (Series A 2022
Bonds) are subject to annual sinking fund redemption at 100% of the
principal amount thereof commencing March 15, 2003. The Series A 2002
Bonds are not subject to optional redemption. The Series A 2022 Bonds are
redeemable at the option of Chugach on any interest payment date at an
initial redemption price commencing in 2002 of 109.140 of the principal
amount thereof declining ratably to par on March 15, 2012. The Bonds are
secured by a first lien on substantially all of Chugach's assets. The
Indenture prohibits outstanding short-term indebtedness (other than trade
payables) in excess of 15% of Chugach's net utility plant and limits
certain cash investments to specific securities.
In April 1997, Chugach reacquired $5,000,000 of the Series A 2022 Bonds
at a premium of 109.7500. Total transaction cost, including accrued
interest and premium, was $5,510,350.
In February 1999, Chugach reacquired $11,000,000 of the Series A 2022
Bonds at a premium of 117.05. Total transaction cost, including accrued
interest and premium, was $13,322,344.
In February 1999, Chugach reacquired $14,000,000 of the Series A 2022
Bonds at a premium of 116.25. Total transaction cost, including accrued
interest and premium, was $16,868,592.
In February 1999, Chugach reacquired $9,895,000 of the Series A 2022
Bonds at a premium of 116.75. Total transaction cost, including accrued
interest and premium, was $11,974,467.
In March 2000, Chugach reacquired $8,500,000 of the Series A 2022 Bonds
at a premium of 104.00. Total transaction cost, including accrued
interest and premium, was $9,215,502.
In April 2000, Chugach reacquired $10,000,000 of the Series A 2022 Bonds
at a premium of 108.875. Total transaction costs, including accrued
interest and premium, was $10,953,511.
On March 17, 1999, Chugach entered into a Treasury rate-lock transaction
with Lehman Brothers Financial Products Inc. (Lehman Brothers) for the
purpose of taking advantage of favorable market interest rates in
anticipation of refinancing Chugach's Series A Bonds due 2022 on their
call date (March 15, 2002). As of December 31, 2000, the aggregate
principal amount of Series A Bonds due 2022 was $164,310,000. Under the
treasury rate-lock contract, Chugach will receive a lump-sum payment
from Lehman Brothers on March 15, 2002, if the yield on 10- or 30-year
Treasury bonds as of mid-February 2002, exceeds a specified target level
(5.653% and 5.838%, respectively). Conversely, Chugach will on the same
date be required to make a payment to Lehman Brothers if the yield on
the 10- or 30-year Treasury bonds falls below its stated target yield.
The treasury rate lock agreement fair value on December 31, 2000 was
$(8,600,000) and on December 31, 1999 was $13,000,000.
Chugach will adopt SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended by SFAS No. 138, on January 1, 2001.
This new standard requires all derivative financial instruments to be
reflected on the balance sheet. As of January 1, 2001, Chugach will
establish a regulatory asset for $8.6 million and a liability for the
same amount. The regulatory asset and liability will be adjusted for
changes in the fair value of the treasury rate lock agreement.
Management believes it is probable the regulatory asset will be
recovered through rates.
(7) Fair Value of Long-Term Obligations
The estimated fair values (in thousands) of the long-term obligations
included in the financial statements at December 31 are as follows:
2000 1999
---- ----
Carrying Fair Carrying Fair
Value Value Value Value
Long-term obligations
(including current installments) $318,650 $335,155 $343,523 $354,534
Fair value estimates are dependent upon subjective assumptions and
involve significant uncertainties resulting in variability in estimates
with changes in assumptions.
(8) Employee Benefits
Employee benefits for substantially all employees are provided through
the Alaska Electrical Trust and Alaska Hotel, Restaurant and Camp
Employees Health and Welfare Trust Funds (union employees) and the
National Rural Electric Cooperative Association (NRECA) Retirement and
Security Program (nonunion employees). The Association makes annual
contributions to the plans equal to the amounts accrued for pension
expense. For the union plans, the Association pays a contractual hourly
amount per union employee which is based on total plan costs for all
employees of all employers participating in the plan. In these master,
multiple-employer plans, the accumulated benefits and plan assets are not
determined or allocated separately to the individual employer. Costs for
union plans were approximately $2,017,000 in 2000, $1,832,000 in 1999 and
$1,805,000 in 1998. In 2000, 1999 and 1998, the Association contributed
$1,057,000, $868,000 and $813,000, respectively, to the NRECA plan.
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
(9) Deferred Charges
Deferred charges consisted of the following at December 31:
2000 1999
----- ----
Debt issuance and reacquisition costs $ 5,399,282 $ 6,196,555
Refurbishment of transmission equipment 253,087 262,346
Computer software and conversion 10,672,135 12,186,272
Studies 1,724,936 1,880,734
Business venture studies 562,435 273,660
Fuel supply negotiations 346,894 369,609
Major overhaul of steam generating unit 222,198 427,305
Environmental matters and other 261,892 470,756
------- ----------
$19,442,859 $22,067,237
=========== ===========
(10) Employee Representation
Approximately 72% of the Association's employees are represented by the
International Brotherhood of Electrical Workers (IBEW). The various IBEW
contracts expire on June 30, 2003.
(11) Return of Capital
Under provisions of its long-term debt agreements, the Association is not
directly or indirectly permitted to declare or pay any dividend or make
any payments, distributions or retirements of patronage capital to
members if an event of default exists with respect to its bonds (event of
default), if payment of such distribution would result in an event of
default, or if the aggregate amount expended for all distributions on and
after September 26, 1991 exceeds the sum of $7,000,000 plus 35% of the
aggregate assignable margins (whether or not such assignable margins have
since been allocated to members) of the Association earned after December
31, 1990 (or, in the case such aggregate shall be a deficit, minus 100%
of such deficit). The Association may declare and make distributions at
any time if, after giving effect thereto, the Association's aggregate
margins and equities as of the end of the most recent fiscal quarter
would be not less than 45% of the Association's total liabilities and
equities as of the date of the distribution. The Association does not
anticipate that this provision will limit the anticipated capital credit
retirements described in note 4.
(12) Deferred Credits
Deferred credits at December 31 consisted of the following:
2000 1999
----- ----
Regulatory liability - unamortized gain on
reacquired debt $18,066,673 $ 21,271,412
Refundable consumer advances for construction 1,771,302 2,123,913
Estimated initial installation costs for transformers and
meters 323,821 272,554
Post retirement benefit obligation 286,200 286,200
New business venture 20,254 46,185
Other 957,089 710,956
------- ----------
$21,425,339 $24,711,220
=========== ============
In conjunction with the refinancing described in note 6, the Association
had recognized a gain of approximately $45,000,000. The APUC required the
Association to flow through the gain to consumers in the form of reduced
rates over a period equal to the life of the bonds using the effective
interest method; consequently, the gain has been deferred for financial
reporting purposes as required by SFAS 71. Approximately $1,553,000 of
the deferred gain was amortized in 2000. Approximately $1,215,000 of the
deferred gain was amortized in 1999. Approximately $1,700,000 of the
deferred gain was amortized in 1998.
(13) Bradley Lake Hydroelectric Project
The Association is a participant in the Bradley Lake Hydroelectric
Project (Bradley Lake). Bradley Lake was built and financed by the Alaska
Energy Authority (AEA) through State of Alaska grants and $166,000,000 of
revenue bonds. The Association and other participating utilities have
entered into take-or-pay power sales agreements under which shares of the
project capacity have been purchased and the participants have agreed to
pay a like percentage of annual costs of the project (including
ownership, operation and maintenance costs, debt service costs and
amounts required to maintain established reserves). Under these
take-or-pay power sales agreements, the participants have agreed to pay
all project costs from the date of commercial operation even if no energy
is produced. The Association has a 30.4% share of the project's capacity.
The share of debt service exclusive of interest, for which the
Association has guaranteed is approximately $44,000,000. Under a worst
case scenario, the Association could be faced with annual expenditures of
approximately $4.1 million as a result of its Bradley Lake take-or-pay
obligations. Management believes that such expenditures, if any, would be
recoverable through the fuel surcharge ratemaking process.
Upon the default of a Bradley Lake participant, and subject to certain
other conditions, AEA, through Alaska Industrial Development and Export
Authority, is entitled to increase each participant's share of costs pro
rata, to the extent necessary to compensate for the failure of another
participant to pay its share, provided that no participant's percentage
share is increased by more than 25%.
On April 6, 1999, AEA issued $59,485,000 of Power Revenue Refunding
Bonds, Third Series, for the purpose of refunding $59,110,000 of the
First Series Bonds. The refunded First Series Bonds were called on July
1, 1999. The refunding resulted in aggregate debt service payments over
the next nineteen years in a total amount approximately $9,500,000 less
than the debt service payments which would be due on the refunded bonds.
There was an economic gain of approximately $5,900,000. Economic gain is
calculated as the net difference between the present value of the old
debt service requirements and the present value of the new debt service
requirements, discounted at the effective interest rate and adjusted for
additional cash paid.
On April 13, 1999, AEA issued $30,640,000 of Power Revenue Refunding
Bonds, Fifth Series, for the purpose of refunding $28,910,000 of the
First Series Bonds. The refunded First Series Bonds were called on July
1, 1999. The refunding resulted in aggregate debt service payments over
the next twenty-three years in a total amount approximately $4,400,000
less than the debt service payments which would be due on the refunded
bonds. There was an economic gain of approximately $2,900,000.
On April 4, 2000, AEA issued $47,710,000 of Power Revenue Refunding
Bonds, Fourth Series, for the purpose of refunding $46,235,000 of the
Second Series Bonds. The refunded Second Series Bonds were called on July
1, 2000. The refunding resulted in aggregate debt service payments over
the next twenty-two years in a total amount approximately $6,400,000 less
than the debt service payment which would be due on the refunded bonds.
There was an economic gain of approximately $3,500,000.
The following represents information with respect to Bradley Lake at June
30, 2000 (the most recent date for which information is available). The
Association's share of expenses were $3,696,829 in 2000, $3,902,737 in
1999 and $4,112,292 in 1998 and are included in purchased power in the
accompanying financial statements.
(In thousands) Total Proportionate Share
-----
Plant in service $ 306,872 $ 93,289
Accumulated depreciation (60,567) (18,170)
Interest expense 9,938 2,981
Other electric plant in service represents the Association's share of a
Bradley Lake transmission line financed internally and the Association's
share of the Eklutna Hydroelectric Project, purchased in 1997 (note 14).
(14) Eklutna Hydroelectric Project
During October 1997, the ownership of the Eklutna Hydroelectric Project
formally transferred from the Alaska Power Administration to the
participating utilities. This group consists of the Association along
with Matanuska Electric Association (MEA) and Municipal Light and Power
(AML&P).
Other electric plant in service includes $1,956,954 representing the
Association's share of the Eklutna Hydroelectric Plant. This balance will
be amortized over the estimated life of the facility. During the
transition phase and after the transfer of ownership, Chugach, MEA and
AML&P have jointly operated the facility. Each participant contributes
their proportionate share for operations and maintenance costs. Under net
billing arrangements, Chugach then reimburses MEA for their share of the
costs.
(15) Commitments and Contingencies
Contingencies
The Association is a participant in various legal actions, rate disputes,
personnel matters and claims both for and against its interests.
Management believes that the outcome of any such matters will not
materially impact the Association's financial condition, results of
operations or liquidity.
Long-Term Fuel Supply Contracts
The Association has entered into long-term fuel supply contracts from
various producers at market terms. The current contracts will expire in
15 to 20 years.
Significant Customers
The Association is the principal supplier of power under long-term
wholesale power contracts with MEA and HEA. These contracts represented
$45.2 million or 28.5% of operating revenues in 2000, and will expire in
2014.
Cooper Lake Hydroelectric Plant
The Association discovered polychlorinated biphenyls ("PCBs") in paint,
caulk and grease at the Cooper Lake Hydroelectric plant during initial
phases of a turbine overhaul. The Association is implementing a plan
approved by the Environmental Protection Agency to remediate the PCBs in
the plant. The Association is also conducting an investigation to
determine whether any PCBs released from the plant are present in Kenai
Lake. The Association does not have an estimate at this time of the
potential costs involved in the investigation and we do not know whether
any additional remediation will be required. Management believes costs of
this endeavor will be recoverable through rates and therefore will have
no material impact on the financial condition or results of operations.
Regulatory Cost Charge
In 1992 the State of Alaska Legislature passed legislation authorizing
the Department of Revenue to collect a regulatory cost charge from
utilities in order to fund the APUC. The tax is assessed on all retail
consumers and is based on kilowatt hour (kWh) consumption. The Regulatory
Cost Charge has decreased since its inception (November 1992) from an
initial rate of $.000626 per kWh to the current rate of $.000318,
effective October 1, 2000.
(16) Segment Reporting
The Association had divided its operations into two reportable
segments: Energy and Internet service. The energy segment derives its
revenues from sales of electricity to residential, commercial and
wholesale customers, while the Internet segment derives its revenues
from provision of residential and commercial internet services and
products. The reporting segments follow the same accounting policies
used for the Association's financial statements and described in the
summary of significant accounting policies. Management evaluates a
segment's performance based upon profit or loss from operations.
Jointly used assets are allocated by percentage of reportable segment
usage and centrally incurred costs are allocated using factors
developed by the Association, which are patterned upon usage. The
Internet segment began operations during 1998, the results of which are
immaterial to the financial statements. The following is a tabulation
of business segment information for the years ended December 31:
Operating Revenues 2000 1999
------------------ ---- ----
Internet $1,170,448 $374,296
Energy 157,370,666 142,270,031
----------- -----------
Total operating revenues 158,541,114 142,644,327
=========== ===========
Assignable Margins
Internet (1,505,518) (1,293,388)
Energy 11,185,296 10,960,822
---------- ----------
Total assignable margins 9,679,778 9,667,434
========= =========
Assets
Internet 550,275 564,477
Energy 539,195,705 517,791,060
----------- -----------
Total assets 539,745,980 518,355,537
=========== ===========
Capital Expenditures
Internet 163,565 508,082
Energy 46,572,794 41,356,746
---------- ----------
Total capital expenditures 46,736,359 41,864,828
========== ==========
(17)
Sale of Segment
On March 6, 2001, the Association entered into an agreement to sell
substantially all the assets and customers of the Internet business
segment to an unrelated third party. The transaction is expected to
result in a nominal gain.
(18) Quarterly Results of Operations (unaudited)
--------------------------------
2000 Quarter Ended
Dec. 31 Sept. 30 June 30 March 31
------- -------- ------- --------
Operating Revenue $44,282,842 $37,201,515 $36,185,683 $40,871,074
Operating Expense 36,351,256 31,192,307 29,183,255 29,703,456
Net Interest 6,384,593 6,078,364 6,114,471 6,140,861
--------- --------- --------- ---------
Net Operating Margins 1,546,993 (69,156) 887,957 5,026,757
Non-Operating Margins 1,450,456 220,261 267,174 349,336
--------- ---------- ---------- ----------
Assignable Margins $2,997,449 $ 151,105 $1,155,131 $5,376,093
========== ========= ========== ==========
1999 Quarter Ended
Dec. 31 Sept. 30 June 30 March 31
------- -------- ------- --------
Operating Revenue $38,837,034 $32,075,076 $32,307,980 $39,424,237
Operating Expense 30,637,296 26,163,772 27,033,946 26,621,873
Net Interest 6,148,973 5,905,993 5,949,006 6,131,408
--------- --------- --------- ---------
Net Operating Margins 2,050,765 5,311 (674,972) 6,670,956
Non-Operating Margins 1,090,556 199,106 170,377 155,335
--------- --------- --------- ---------
Assignable Margins $3,141,321 $ 204,417 $(504,595) $6,826,291
========== ========= ========== ==========
Item 9 - Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure
None
PART III
Item 10 - Directors and Executive Officers of the Registrant
Management
We operate under the direction of a Board of Directors that is elected
at large by our membership. Day-to-day business and affairs are administered by
the General Manager. Our seven-member Board of Directors sets policy and
provides direction to our General Manager. The following table sets forth
certain information with respect to our executive officers and directors.
Name Age Position
Eugene N. Bjornstad......................... 62 General Manager
Lee D. Thibert.............................. 45 Executive Manager,Transmission and Distribution Network Services
Evan J. Griffith............................ 59 Executive Manager, Finance and Energy Supply
William R. Stewart.......................... 54 Executive Manager, Retail Services
Pat Jasper.................................. 72 President and Director
Christopher Birch........................... 50 Vice President and Director
Bruce Davison............................... 53 Secretary and Director
Mary Minder................................. 61 Treasurer and Director
Elizabeth ("Pat") Kennedy................... 62 Director
Jeffrey W. Lipscomb......................... 50 Director
H. A. ("Red") Boucher....................... 80 Director
Executive Officers
Eugene N. Bjornstad was appointed our General Manager on June 22, 1994.
Prior to that he served as Acting General Manager from March 28, 1994, until his
permanent appointment. He joined Chugach in 1983 and served as Executive
Manager, Operating Divisions from 1988 to 1994.
Lee D. Thibert, in a reorganization on June 1, 1997, was appointed our
Executive Manager, Transmission & Distribution Network Services. Prior to that
he was Executive Manager, Operating Divisions from June of 1994. Before moving
up to the Executive Manager position, he served as Director of Operations from
May 1987.
Evan J. Griffith has been our Executive Manager, Finance and Energy
Supply since our internal reorganization on June 1, 1997. Prior to that, he was
Executive Manager, Finance & Planning from August 1989 to June 1997. Prior to
coming to us, he was Budget/Program Analyst for the Anchorage Municipal Assembly
from August 1984 to August 1989.
William R. Stewart has been our Executive Manager, Retail Services
since the June 1, 1997 reorganization. Prior to that, he was our Executive
Manager, Administration from July 1987 to June 1, 1997. He was our Division
Director of Administration from January 1984 to July 1987 and Staff Assistant to
the General Manager of Chugach from November 1982 to January 1984. He has been
employed by us since 1969.
Board of Directors
Pat Jasper has served as the President of the Board since April 2000.
Ms. Jasper was originally elected to the Board in April 1995. Since 1995, she
has held several offices including Secretary, Vice President and President. She
is a small business owner and has been a computer programmer and systems
analyst.
Pat Kennedy serves as Vice President of the Board. Ms. Kennedy has
served on the board since 1993 and has served as both Secretary and President
before holding her current position. She is an attorney who has been licensed to
practice law since 1976 and has been in private practice since 1990.
Bruce Davison has served as the Secretary of the Board since
April 1998. Mr. Davison was first appointed to the Board of Directors in
June 1997. Prior to his appointment, he served two years on the Chugach
Bylaws Committee. He is a partner in the law firm of Davison & Davison, Inc.
Mary Minder has been the Treasurer since April 1997. Ms. Minder was
elected to the Board in April 1995 and since then has served as both Treasurer
and Secretary. She is a realtor and associate real estate broker.
Chris Birch was appointed to fill a Board vacancy in October 1996. Mr.
Birch was elected to that seat in April 1997 and since that time has served as a
director. He has previously served as Secretary and President. He is a
professional engineer for the Alaska Department of Transportation and Public
Facilities.
Red Boucher was elected to the Board in April 1999. In addition to
being a director, Mr. Boucher owns a consulting firm, serves as president of a
telecommunication firm and hosts a weekly statewide TV show. He has held many
elected offices including Lieutenant Governor of Alaska.
Jeff Lipscomb is the newest member of the Board and was elected
director in April 2000. Mr. Lipscomb is the principal of JWL Engineering which
he founded in 1995. He is a professional civil engineer with over 20 years of
experience in Alaskan oil and gas production facility design.
Item 11 - Executive Compensation
Cash Compensation
.........The following table sets forth all remuneration paid by us for the last
three years to each of our four executive officers, each of whose total cash and
cash equivalent compensation exceeded $100,000 for 2000, and for all such
executive officers as a group:
Name Principal Position Year Salary Bonus Total
Eugene N. Bjornstad General Manager 2000 $230,074 $ 01 $230,074
1999 $168,057 $ 36,891 $204,948
1998 $166,427 $ 33,996 $200,423
Lee D. Thibert Executive Manager, 2000 $131,710 $ 01 $131,710
Transmission & 1999 $123,390 $ 12,757 $136,147
Distribution
Network Services 1998 $125,880 $ 0 $125,880
Evan J. Griffith Executive Manager, 2000 $131,657 $ 01 $131,657
Finance
& Energy Supply 1999 $135,140 $ 12,757 $147,897
1998 $131,634 $ 3,300 $134,934
William R. Stewart Executive Manager, 2000 $134,398 $ 01 $134,398
Retail Services 1999 $137,376 $ 12,757 $150,133
1998 $140,193 $ 3,300 $143,493
1Year 2000 bonuses have not been granted.
Our directors are compensated for their services in the amount of $100
per board meeting attended (including committee meetings) up to a maximum of
seventy meetings per year for a director and eighty-five meetings per year for
the President. Upon termination, Mr. Bjornstad's employment agreement provides
that he may receive an amount equal to his salary for the greater of six months
or remaining term of his employment agreement (which number shall not be less
than six months) plus any accrued annual leave or other compensation then due as
of the effective date of the notice of termination.
Compensation Pursuant to Plans
We have elected to participate in the National Rural Electric
Cooperative Association ("NRECA") Retirement and Security Program (the "Plan"),
a multiple employer defined benefit master pension plan maintained and
administered by the NRECA for the benefit of its members and their employees.
The Plan is intended to be a qualified pension plan under Section 401(a) of the
Code. All our employees not covered by a union agreement become participants in
the Plan on the first day of the month following completion of one year of
eligibility service. An employee is credited with one year of eligibility
service if he completes 1,000 hours of service either in his first twelve
consecutive months of employment or in any calendar year for Chugach or certain
other employers in rural electrification (related employers). Pension benefits
vest at the rate of 10% for each of the first four years of vesting service and
become fully vested and nonforfeitable on the earlier of the date a participant
has five years of vesting service or the date the participant attains age
fifty-five while employed by us or a related employer. A participant is credited
with one year of vesting service for each calendar year in which he performs at
least one hour of service for us or a related employer. Pension benefits are
generally paid upon the participant's retirement or death. A participant may
also elect to receive pension benefits while still employed by us if he has
reached his normal retirement date by completing thirty years of benefit service
(as hereinafter defined) or, if earlier, by attaining age sixty-two. A
participant may elect to receive actuarially reduced early retirement pension
benefits before his normal retirement date provided he has attained age
fifty-five.
Pension benefits paid in normal form are paid monthly for the remaining
lifetime of the participant. Unless an actuarially equivalent optional form of
benefit payment to the participant is elected, upon the death of a participant
the participant's surviving spouse will receive pension benefits for life equal
to 50% of the participant's benefit. The annual amount of a participant's
pension benefit and the resulting monthly payments the participant receives
under the normal form of payment are based on the number of his years of
participation in the Plan (benefit service) and the highest five-year average of
the annual rate of his base salary during the last ten years of his
participation in the Plan (final average salary). Annual compensation in excess
of $200,000, as adjusted by the Internal Revenue Service for cost of living
increases, is disregarded after January 1, 1989. The participant's annual
pension benefit at his normal retirement date is equal to the product of his
years of benefit service (up to thirty) times final average salary times 2%. In
1998, NRECA notified us that there were employees whose pension benefits from
NRECA's Retirement & Security Program would be reduced because of limitations on
retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA
made available a Pension Restoration Severance Pay Plan and a Pension
Restoration Deferred Compensation Plan for cooperatives to adopt in order to
make employees whole for their lost benefits. In May 1998, we adopted both of
these plans to protect the benefits of current and future employees whose
pension benefits would be reduced because of these limitations.
The following table sets forth the estimated annual pension benefit
payable at normal retirement date for participants in the specified final
average salary and years of benefit service categories:
Final Average
Salary Years of Benefit Service
15 20 25 30+
-- -- -- ---
$125,000 $37,500 $50,000 $62,500 $75,000
$150,000 $45,000 $60,000 $75,000 $90,000
The annual pension benefits indicated above are the joint and surviving
spouse life annuity amounts payable by the Plan, and they are not subject to any
deduction for Social Security or other offset amounts.
Benefit service as of December 31, 2000 taken into account under the
Plan for the executive officers is shown below. Base salary for 2000 taken into
account under the Plan for purposes of determining final average salary is also
included.
Name Principal Position Benefit Service Covered Compensation
Eugene N. Bjornstad........... General Manager 16.7 $165,027
Lee D. Thibert................ Executive Manager, Transmission 12.7 $130,790
& Distribution Network ServicesE
Evan J. Griffith.............. Executive Manager, Finance & 10.4 $130,166
Energy Supply
William R. Stewart............ Executive Manager, Retail 30.0 $130,187
Services
Item 12 - Security Ownership of
Certain Beneficial Owners and Management
Not Applicable
Item 13 - Certain Relationships and Related Transactions
Not Applicable
PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
Page
Financial Statements
Included in Part IV of this Report:
Independent Auditors' Report 28
Balance Sheets, December 31, 2000 and 1999 29-30
Statements of Revenues, Expenses and Patronage Capital,
Years ended December 31, 2000, 1999 and 1998 31
Statements of Cash Flows,
Years ended December 31, 2000, 1999 and 1998 32
Notes to Financial Statements 33-50
Financial Statement Schedules
Included in Part IV of this Report:
Schedule II - Valuation and Qualifying Accounts,
Years ended December 31, 2000, 1999 and 1998 57
Other schedules are omitted as they are not required or are not applicable, or
the required information is shown in the applicable financial statements or
notes thereto.
Schedule II
CHUGACH ELECTRIC ASSOCIATION, INC.
Valuation and Qualifying Accounts
Balance at Charged Balance
Beginning To costs at end
of year And expenses Deductions of year
------- ------------- ---------- -------
Allowance for doubtful accounts:
Activity for year ended:
December 31, 2000 $(389,223) $(373,666) $320,956 $(441,933)
December 31, 1999 (447,908) (331,895) 390,580 (389,223)
December 31, 1998 (368,029) (407,825) 327,946 (447,908)
EXHIBITS
Listed below are the exhibits which are filed as part of this Report:
Exhibit Number Description
(7) 3.1 Articles of Incorporation of the Registrant.
(9) 3.2 Bylaws of the Registrant.
(1) 4.1 Trust Indenture between the Registrant and Security Pacific
Bank Washington, N.A. dated as of September 15, 1991 (including
forms of bonds).
(1) 4.2 First Supplemental Indenture of Trust between the
Registrant and Seattle-First National Bank dated March
17, 1993.
(1) 4.3 Second Supplemental Indenture of Trust between the Registrant and
Seattle First National Bank dated May 19, 1994.
(1) 4.4 Third Supplemental Indenture of Trust between the Registrant and
Seattle First National Bank dated June 29, 1994.
(1) 4.5 Fourth Supplemental Indenture of Trust between the
Registrant and Seattle-First National Bank dated March
1, 1995.
(1) 4.6 Fifth Supplemental Indenture of Trust between the
Registrant and Seattle-First National Bank dated
September 6, 1995.
(1) 4.7 Sixth Supplemental Indenture of Trust between the
Registrant and Seattle-First National Bank dated April
3, 1996.
(2) 4.8 Seventh Supplemental Indenture of Trust between the
Registrant and Seattle-First National Bank dated June
1, 1997.
(4) 4.9 Eighth Supplemental Indenture of Trust between the Registrant and
Security Pacific Bank Washington, N.A. dated February 4, 1998.
(9) 4.10 Ninth Supplemental Indenture of Trust between the Registrant and U.S.
Bank Trust National Association dated April 25, 2000.
4.13 Form of Debt Security (included in Exhibit 4.1).
(1) 10.1 Wholesale Power Agreement between the Registrant and the City of
Seward.
(1) 10.2 Joint Use Agreement between the Registrant and the
City of Seward dated effective as of September 11,
1998.
(1) 10.3 Net Billing Agreement among the Registrant and the
City of Seward dated effective as of September 11,
1998.
(8) 10.4 Agreement for the Sale and Purchase of Electric
Power and Energy between the Registrant and the City of
Seward dated effective as of September 11, 1998.
(1) 10.5 Agreement for Sale of Electric Power and Energy by and among the
Registrant, Homer Electric Association,Inc. and Alaska Electric Generation
and Transmission Cooperative, Inc. dated September 27, 1985.
(1) 10.6 Modified Agreement for the Sale and Purchase of Electric Power and
Energy by and among the Registrant, Matanuska Electric Association, Inc.
and Alaska Electric Generation and Transmission Cooperative, Inc. dated
effective as of January 30, 1989.
(1) 10.6.1 First Amendment to Modified Agreement for the Sale and Purchase of
Electric Power and Energy by and among the Registrant, Matanuska Electric
Association, Inc. and Alaska Electric Generation and Transmission
Cooperative, Inc. dated effective as of February 10, 1995.
(1) 10.6.2 Net Billing Agreement by and among the Registrant, Matanuska
Electric Association, Inc. and Alaska Electric Generation and Transmission
Cooperative, Inc. dated December 16, 1987.
(1) 10.7 Nonfirm Energy Agreement between the Registrant and Golden Valley
Electric Association, Inc. dated May 18, 1988.
(11)10.7.1 Amendatory Agreement No. 1 to Nonfirm Energy Agreement between the
Registrant and Golden Valley Electric Association, Inc., dated December 14,
1989.
(11)10.7.2 Letter Agreement dated January 18, 1996 between the Registrant and
Golden Valley Electric Association, Inc., amending the Nonfirm Energy
Agreement between the Registrant and Golden Valley Electric Association,
Inc.
(11)10.7.3 Amendatory Agreement No. 2 to Nonfirm Energy Agreement between the
Registrant and Golden Valley Electric Association, Inc., dated February 8,
1999.
(11)10.7.4 Settlement Agreement by and among the Registrant, Golden Valley
Electric Association, Inc. and the Municipality of Anchorage d/b/a
Anchorage Municipal Light and Power dated May 6, 1999.
(1) 10.8 Agreement for the Sale and Purchase of Natural Gas between the
Registrant and ARCO Alaska, Inc. dated April 21, 1989.
(1) 10.8.1 Amendment No. 1 to Agreement for the Sale and Purchase of Natural
Gas between the Registrant and ARCO Alaska, Inc., dated August 1, 1990.
(11)10.8.2 Letter Agreement dated April 23, 1999, regarding
the Registrant's consent to the assignment to ARCO
Beluga, Inc. of the Agreement for the Sale and Purchase
of Natural Gas between the Registrant and ARCO Alaska,
Inc.
(8) 10.8.3 Amendment No. 2 to Agreement for the Sale and Purchase of Natural
Gas between the Registrant and ARCO Beluga, Inc., dated May 6, 1999.
(1) 10.9 Agreement for the Sale and Purchase of Supplemental Natural Gas
between the Registrant and ARCO Alaska, Inc. dated October 3, 1991.
(1) 10.10 Agreement for the Sale and Purchase of Natural
Gas between the Registrant and Marathon Oil Company
dated September 26, 1988.
(1) 10.10.1 Letter Agreement dated September 26, 1988
between the Registrant and Marathon Oil Company,
amending the Agreement for the Sale and Purchase of
Natural Gas between the Registrant and Marathon Oil
Company.
(1) 10.10.2 Amendatory Agreement No. 1 to Agreement for the Sale and Purchase
of Natural Gas between the Registrant and Marathon Oil Company, dated
effective as of February 21, 1990.
(1) 10.10.3 Amendatory Agreement No. 2 to Agreement for the Sale and Purchase
of Natural Gas between the Registrant and Marathon Oil Company, dated
effective as of February 21, 1990.
(1) 10.10.4 Amendatory Agreement No. 3 to Agreement for the Sale and Purchase
of Natural Gas between the Registrant and Marathon Oil Company, dated
January 28, 1991.
(11)10.10.5 Amendatory Agreement No. 4 to Agreement for the Sale and Purchase
of Natural Gas between the Registrant and Marathon Oil Company, dated
October 6, 1993.
(11)10.10.6 Letter Agreement dated January 18, 1996 between
the Registrant and Marathon Oil Company, amending the
Agreement for the Sale and Purchase of Natural Gas
between the Registrant and Marathon Oil Company.
(8) 10.10.7 Amendatory Agreement No. 5 to Agreement for the Sale and Purchase
of Natural Gas between the Registrant and Marathon Oil Company, dated
May 24, 1999.
(1) 10.11 Agreement for the Sale and Purchase of Natural Gas between the
Registrant and Shell Western E&P Inc. dated April 25, 1989.
(1) 10.11.1 Amendatory Agreement No. 1 to the Agreement for the Sale of Natural
Gas between the Registrant and Shell Western E&P Inc., dated October 1,
1989.
(1) 10.11.2 Amendment No. 2 to the Agreement for the Sale of Natural Gas
between the Registrant and Shell Western E&P Inc., dated June 20, 1990.
(1) 10.11.3 Amendatory Agreement No. 3 to the Agreement for the Sale of Natural
Gas between the Registrant and Shell Western E&P Inc. dated October 14,
1996.
(1) 10.12 Agreement for the Sale and Purchase of Supplemental Natural Gas
between the Registrant and Shell Western E&P Inc. dated November 2, 1990.
(1) 10.13 Agreement for the Sale and Purchase of Natural Gas between the
Registrant and Chevron USA Inc. dated April 27, 1989 (including Attachment
No. 1 thereto dated December 20, 1989).
(1) 10.13.2 Amendment No. 2 to Agreement for the Sale and Purchase of Natural
Gas between the Registrant and Chevron USA Inc., dated June 7, 1990.
(8) 10.13.3 Amendment No. 3 to Agreement for the Sale and Purchase of Natural
Gas between the Registrant and Chevron U.S.A. Inc., dated May 26, 1999.
(1) 10.14 Agreement for the Sale and Purchase of Supplemental Natural Gas
between the Registrant and Chevron USA, Inc. dated September 25, 1990.
(1) 10.15 Alaska Intertie Agreement between Alaska Power Authority,
Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska
Municipal Utilities System, Golden Valley Electric Association, Inc. and
Alaska Electric Generation and Transmission Cooperative, Inc. dated December
23, 1985.
(1) 10.16 Addendum No. 1 to the Alaska Intertie Agreement-Reserve Capacity and
Operating Reserve Responsibility dated December 23, 1985.
(1) 10.17 Memorandum of Understanding Regarding Intertie Upgrades among Alaska
Energy Authority, the Registrant, Golden Valley Electric Association, Inc.,
Homer Electric Association, Inc., Matanuska Electric Association, Inc.,
Municipality of Anchorage d/b/a Municipal Light and Power, and the City of
Seward d/b/a Seward Electric System dated March 21, 1990.
(11)10.18 Amendment No. 1 to the Alaska Intertie Agreement-Insurance and
Liability dated March 28, 1991.
(1) 10.19 Intertie Grant Agreement between the Registrant, Golden Valley
Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage
Municipal Light and Power, Alaska Electric Generation and Transmission
Cooperative, Inc. (on behalf of Matanuska Electric Association, Inc. and
Homer Electric Association, Inc.), City of Seward, the State of Alaska,
Department of Administration and Alaska Industrial Development and Export
Authority dated August 17, 1993.
(1) 10.20 Grant Transfer and Delegation Agreement between the Registrant and
Golden Valley Electric Association, Inc., Fairbanks Municipal Utility
System, Anchorage Municipal Light and Power, Alaska Electric Generation and
Transmission Cooperative, Inc., Matanuska Electric Association, Inc., Homer
Electric Association, Inc., Seward, the State of Alaska, Department of
Administration, and AMEA dated November 5, 1993.
(11)10.21 1993 Alaska Intertie Project Participants Agreement by and among
Alaska Power Authority, Municipality of Anchorage, the Registrant, City of
Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric
Association, Inc., Alaska Electric Generation and Transmission Cooperative,
Inc., City of Seward d/b/a Seward Electric System, Homer Electric
Association, Inc. and Matanuska Electric Association, Inc. dated January 24,
1994.
(11)10.22 Amendment No. 1 to the 1993 Alaska Intertie Project Participants
Agreement dated December 10, 1999.
(11)10.23 Grant Administration Agreement by and among the Registrant, Alaska
Industrial Development and Export Authority, Golden Valley Electric
Association, Inc., Fairbanks Municipal Utilities System, Anchorage Municipal
Light & Power, Alaska Electric Generation and Transmission Cooperative, Inc.
(on behalf of Homer Electric Association, Inc. and Matanuska Electric
Association, Inc.) and City of Seward dated August 30, 1994.
(1) 10.24 Bradley Lake Agreement for the Sale and Purchase of Electric Power by
and among the Registrant, the Alaska Power Authority, Golden Valley Electric
Association, Inc., the Municipality of Anchorage, the City of Seward, the
Alaska Electric Generation and Transmission Cooperative, Inc., Homer
Electric Association, Inc. and Matanuska Electric Association Inc. dated
December 8, 1987.
(1) 10.25 Agreement for the Wheeling of Electric Power and for Related Services
by and among the Registrant, Homer Electric Association, Inc., Golden Valley
Electric Association, Inc., Matanuska Electric Association, Inc., the
Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of
Seward d/b/a Seward Electric System and Alaska Electric Generation and
Transmission Cooperative, Inc. dated December 8, 1987.
(1) 10.26 Transmission Sharing Agreement by and among the Registrant, Homer
Electric Association, Inc., Golden Valley Electric Association, Inc. and the
Municipality of Anchorage d/b/a Municipal Light and Power.
(1) 10.27 Amendment to Agreement for Sale of Transmission Capability by and
among the Registrant, Homer Electric Association, Inc., Alaska Electric
Generation and Transmission Cooperative, Inc., Golden Valley Electric
Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light
and Power dated March 7, 1989.
(1) 10.28 Bradley Lake Hydroelectric Agreement for the
Dispatch of Electric Power and for Related Services
between the Registrant and the Alaska Energy Authority
dated February 19, 1992.
(1) 10.29 Agreement for Bradley Lake Resource Scheduling by and among the
Registrant, Homer Electric Association, Inc. and the Alaska Electric
Generation and Transmission Cooperative, Inc. dated September 29, 1992.
(1) 10.30 Interconnection Agreement between the Registrant
and Municipality of Anchorage Municipal Light and Power
dated December 2, 1983.
(1) 10.30.1 Addendum No. 1 to Interconnection Agreement between the Registrant
and Municipality of Anchorage Municipal Light and Power dated August 8,
1984.
(1) 10.30.2 Amendment No. 1 to Interconnection Agreement between the Registrant
and Municipality of Anchorage Municipal Light and Power dated November 28,
1984.
(1) 10.31 Gas Transportation Agreement by and among the Registrant, Alaska
Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992.
(1) 10.32 Eklutna Purchase Agreement by and among the Registrant, Matanuska
Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light
and Power and Alaska Power Administration.
(3) 10.33 Eklutna Hydroelectric Project Closing Documents dated October 2,
1997.
(1) 10.34 Settlement Agreement by and among the Registrant, Homer Electric
Association, Inc., Matanuska Electric Association, Inc., the City of Seward
and Alaska Electric Generation and Transmission Cooperative, Inc., resolving
G&T TIER Level, Equity Level, Capital Credits, Equity Management Plan and
Loan Covenant Disputes, dated effective as of February 3, 1993.
(1) 10.35 First Amendment to "Settlement Agreement Resolving G&T TIER Level,
Equity Level, Capital Credits, Equity Management Plan and Loan Covenant
Disputes" in APUC Docket U-92-10 between the Registrant, Matanuska
Electric Association, Inc., Homer Electric Association, Inc. and the Alaska
Electric Generation and Transmission Cooperative, Inc. dated March 1993.
(1) 10.36 Agreement by and among the Registrant, Municipality of Anchorage
d/b/a Anchorage Municipal Light and Power, Matanuska Electric Association,
Inc., U.S. Fish and Wildlife Service, National Marine Fisheries Service,
Alaska Energy Authority and the State of Alaska re: the Eklutna and
Snettisham Hydroelectric Projects.
(1) 10.37 Daves Creek Substation Agreement between the Registrant and the
Alaska Energy Authority dated March 13, 1992.
(1) 10.38 Settlement Agreement between the Registrant and
Intervenor Wholesale Customers in APUC Docket U-93-15
dated September 1993 regarding depreciation of
submarine cables.
(8) 10.39 Nikiski Cogeneration Plant System Use and Dispatch Agreement between
the Registrant and Alaska Electric Generation and Transmission Cooperative,
Inc. dated February 12, 1999.
(1) 10.40 Lease Amendment between the Registrant and Standard Oil Company
of California dated June 1, 1975.
(1) 10.41 Lease Amendment between the Registrant and Chevron USA, Inc. dated
September 1, 1985.
(1) 10.42 Loan Agreement between the Registrant and the
National Bank for Cooperatives (formerly Spokane Bank
for Cooperatives), as amended.
(1) 10.43 Amendment to Loan Agreement between the
Registrant and the National Bank for Cooperatives dated
September 13, 1991.
(1) 10.44 Twenty Five Million Dollar Line of Credit Agreement and Promissory
Note between the Registrant and the National Bank for Cooperatives.
(1) 10.44.1 Amendment to Line of Credit Agreement between
the Registrant and the National Bank for Cooperatives
dated March 11, 1994.
(1) 10.44.2 Amendment to Line of Credit Agreement between
the Registrant and the National Bank for Cooperatives
and amended and restated Promissory Note (thirty-five
million dollars) dated April 18, 1994.
(1) 10.44.3 Amendment to Line of Credit Agreement between
the Registrant and the National Bank for Cooperatives
(thirty-five million dollars) dated May 1, 1995.
(1) 10.44.4 Amendment to Line of Credit Agreement between
the Registrant and the National Bank for Cooperatives
(thirty-five million dollars) dated May 15, 1995.
(10)10.44.5 Amendment to Line of Credit Agreement between the Registrant
and CoBank, ACB dated September 30, 2000.
(2) 10.45 National Bank for Cooperatives (CoBank) Credit Agreement dated June
22, 1994.
(2) 10.46 Amendment No. 1 to National Bank for Cooperatives (CoBank) Credit
Agreement, dated June 1, 1997.
(3) 10.47 Fifty Million Dollar Line of Credit Agreement
between the Registrant and the National Rural Utilities
Cooperative Finance Corporation dated October 22, 1997.
(6) 10.48 International Swap Dealers Association, Inc. Master Agreement
between the Registrant and Lehman Brothers Financial Products Inc. dated
March 17, 1999.
(7) 10.49 Confirmation for U.S. dollar Treasury rate-lock transaction to be
subject to 1992 Master Agreement between the Registrant and Lehman Brothers
Financial Products Inc. dated March 17, 1999.
(1) 10.50 Employment Agreement between the Registrant and Eugene N. Bjornstad
dated July 6, 1994.
(4) 10.51 Amendment to Employment Agreement by and among the Registrant and
Eugene N. Bjornstad dated February 25, 1998.
(5) 10.52 Settlement Agreement by and among the Registrant,
Nationwide Mutual Insurance Company, Alaska National
Insurance Company, Providence Washington Insurance
Company and Admiral Insurance Company dated May 15,
1998.
(11) 12.1 Statement regarding computation of ratios.
(1) Previously referred to in the Registrant's Annual Report on
Form 10-K dated December 31, 1996.
(2) Previously filed as an exhibit to the Registrant's
Quarterly Report on Form 10-Q dated September 30, 1997.
(3) Previously filed as an exhibit to the Registrant's Annual
Report on Form 10-K dated December 31, 1997.
(4) Previously filed as an exhibit to the Registrant's Quarterly
Report on Form 10-Q dated March 31, 1998.
(5) Previously filed as an exhibit to the Registrant's Quarterly
Report on Form 10-Q dated June 30, 1998.
(6) Previously filed as an exhibit to the Registrant's Annual
Report on Form 10-K dated December 31, 1998.
(7) Previously filed as an exhibit to the Registrant's Quarterly
Report on Form 10-Q dated March 31, 1999.
(8) Previously filed as an exhibit to the Registrant's Quarterly
Report on Form 10-Q dated June 30, 1999.
(9) Previously filed as an exhibit to the Registrant's Quarterly
Report on Form 10-Q dated March 31, 2000.
(10)Previously filed as an exhibit to the Registrant's
Quarterly Report on Form 10-Q dated September 30, 2000.
(11)Previously filed as an exhibit to the Registrant's
Registration Statement on Form S-1 dated March 22, 2001.
REPORTS ON FORM 8-K
The Company was not required to file any report on Form 8K for the year ended
December 31, 2000.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized on March 30, 2001.
CHUGACH ELECTRIC ASSOCIATION, INC.
By: /s/ Eugene N. Bjornstad
Eugene N. Bjornstad, General Manager
Date: March 30, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated March 30, 2001:
/s/ Eugene N. Bjornstad
Eugene N. Bjornstad General Manager
/s/ Lee D. Thibert
Lee D. Thibert Executive Manager, T&D Network Services
/s/ Evan J. Griffith
Evan J. Griffith Executive Manager, Finance & Energy Supply
(Principal Financial officer)
/s/ William R. Stewart
William R. Stewart Executive Manager, Retail Services
/s/ Michael R. Cunningham
Michael R. Cunningham Controller
(Principal Accounting officer)
/s/ Patricia B. Jasper
Patricia B. Jasper President
(Principal Executive Officer & Director)
/s/ Elizabeth Page Kennedy
Elizabeth Page Kennedy Director & Vice President
/s/ Bruce Davison
Bruce Davison Director & Secretary
/s/ Mary Minder
Mary Minder Director & Treasurer
/s/ H.A. Boucher
H.A. Boucher Director
/s/ Christopher Birch
Christopher Birch Director
/s/ Jeffrey Lipscomb
Jeffrey Lipscomb Director
Supplemental information to be furnished with reports filed pursuant to Section
15(d) of the Act by registrants which have not registered securities pursuant to
Section 12, of the Act:
Chugach has not made an Annual Report to securities holders for 2000 and will
not make such a report after the filing of this Form 10-K. As a consequence, no
copies of any such report will be furnished to the Securities and Exchange
Commission.