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, 2001
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()Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the transition period from_______________________to_________________________
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(Exact name of registrant as specified in its charter)
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(State or other jurisdiction of
incorporation or organization) (I.R.S. Employer Identification No.)
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(Address of principal executive offices) (Zip Code)
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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
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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 Securities 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.
2001 Form 10-K Annual Report
Table of Contents
PART I Page
Item 1 - Business 1
Item 2 - Properties 9
Item 3 - Legal Proceedings 17
Item 4 - Submission of Matters to a Vote of Security Holders 18
PART II
Item 5 - Market for Registrant's Common Equity and Related
Stockholder Matters 18
Item 6 - Selected Financial Data 19
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations 20
Item 7A- Quantitative and Qualitative Disclosures About Market Risk 34
Item 8 - Financial Statements and Supplementary Data 36
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 66
PART III
Item 10- Directors and Executive Officers of the Registrant 66
Item 11- Executive Compensation 69
Item 12- Security Ownership of Certain Beneficial Owners and Management 72
Item 13- Certain Relationships and Related Transactions 72
Item 14- Exhibits, Financial Statement Schedules and Reports on Form 8-K 72
SIGNATURES 83
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 70,400 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 527 megawatts of installed generating capacity provided by 17
generating units at our five owned power plants: Beluga Power Plant, Bernice
Lake Power Plant, International Power Plant, Cooper Lake Hydroelectric Plant and
Eklutna Hydroelectric Project, in which we own a 30% interest. Approximately 94%
(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 2001, approximately 90% 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 1,610 miles of distribution line and
402 miles of transmission line. For the year ended December 31, 2001, we sold
2.3 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 other than reasonable reserves and margins. 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, 2001, we had 59,957 retail members receiving service at
approximately 70,416 metered locations and three major wholesale customers. No
individual retail customer receives more than 5% of our power.
Our customers are billed per a tariff rate on a monthly basis for
electrical power consumed during the preceding period. 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) are established
to 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 currently collect a regulatory cost charge of
$.000360 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 354 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 (HERE), Local 878 in
effect through June 30, 2003. We believe our relationship with our employees is
good.
Gene Bjornstad, Chugach's General Manager, has given notice of his
intention to retire in May 2002. Mr. Bjornstad joined Chugach in 1983 and has
served as Executive Manager, Operating Divisions and Acting General Manager
before his appointment as General Manager in June of 1994.
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 located in the south central portion of Alaska and 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. 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. A major gold mine operates near Fairbanks; another is being
developed. The Trans-Alaska Pipeline System (which transports crude oil) passes
near Fairbanks on its route from the North Slope oilfield to Valdez. Alyeska
Pipeline Company, which operates the Trans-Alaska oil pipeline from Prudhoe Bay
to Valdez, has its main operations base in Fairbanks.
Competition
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 the RCA permit us access
over a neighboring utility's distribution and transmission system. 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. Nearly all
other Alaskan utilities have opposed our efforts to develop retail competition
and are treating their service territories as exclusive. At this time no bill
relating to customer choice has moved out of committee in the Alaskan
legislature. We do not expect the legislature to pass a law granting retail
competition for electric service in the foreseeable future.
We have made organizational changes in preparation for retail
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 retail competition in the electric industry should it develop.
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
The RCA regulates our rates. We can seek increases in our base rates
and fuel surcharge 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 courts. 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.
Under Alaska law, a cooperative utility that is negotiating to enter into a
mortgage or other debt instrument that provides for a Times Interest Earned
Ratio (TIER) greater than the ratio the RCA most recently approved for that
cooperative must submit the mortgage or debt instrument to the RCA before the
instrument takes effect. However, the rate covenant contained in the Amended
Indenture will impose no greater TIER requirement than does the rate covenant
contained in the Indenture. We do not expect the requirements of either the
Indenture or the Amended Indenture to exceed the TIER most recently approved for
us by the RCA.
We expect to 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 - Overview."
The 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. On the release date, the Amended Indenture will supersede the
Indenture and require us to set rates designed to yield margins for interest
equal to at least 1.10 times total interest expense. Under RCA orders
establishing our current base rates, we are permitted to achieve a TIER of 1.35.
For the year ended December 31, 2001, our achieved TIER was 1.20.
In our general rate case filed July 10, 2001, based on the 2000 test
year, we proposed that margins be calculated using a rate base/rate of return
methodology rather than the TIER methodology previously used. Under this
methodology, we can assign different rates of return to our various business
functions, such as generation, transmission and distribution, in order to
recover appropriate margins for each individual function. In addition, the
change in methodology allows us to more efficiently allocate our cost of funds.
The resultant system TIER would be 1.38 based on the proposed capital structure
contained in that filing. We do not believe that our request to change from the
TIER-based methodology to the return-on-rate-base methodology will have any
material adverse effect on future ratemaking or on our ability to service our
outstanding indebtedness.
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, 2001:
Percent of Total
MWh 2001 Revenues 2001 Revenues
--- ------------- -------------
Direct retail sales:
Residential.................... 521,557 $58,139,978 33%
Commercial..................... 590,626 53,886,144 31%
------- ---------- ---
Total.......................... 1,112,183 $112,026,122 64%
Wholesale sales:
MEA............................ 566,481 $33,706,678 19%
HEA............................ 448,570 24,260,072 14%
Seward......................... 60,095 2,816,970 1%
------ --------- --
Total.......................... 1,075,146 $60,783,720 34%
Economy energy sales(1) ............ 81,924 $3,354,719 2%
------ ---------
Total sales to customers............ 2,269,253 $176,164,561 100%
========= ====
Miscellaneous energy revenue $2,430,653
---------
Total energy revenues $178,595,214
============
<FN>
(1) Economy sales were made to GVEA and AML&P.
Retail Customers
</FN>
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
As of December 31, 2001, we had 59,957 members being served by
approximately 70,400 meters (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 HEA under
separate wholesale power contracts. For 2001, our wholesale power contracts, not
including the fuel component, produced $60.8 million in revenues, representing
34% of our revenues and 47% of our total kWh sales to customers.
MEA and HEA
We have two power sales contracts with Alaska Electric Generation &
Transmission Cooperative, Inc. (AEG&T): one for sales to MEA and one for sales
to HEA. AEG&T is a generation and transmission cooperative that was formed by
MEA and HEA. Under each of these contracts, we sell power to AEG&T, which
resells the power to MEA and HEA. MEA and HEA have recently indicated that they
may be disbanding or substantially changing their relationship with AEG&T but no
changes to our contracts have been made at this time. Under our contracts, each
of MEA and HEA is obligated to pay us for the power sold to AEG&T even if AGE&T
does not pay.
Under the contract, MEA is obligated 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. MEA has not invoked this right at this time.
If MEA converts to a net requirements purchaser under the contract, MEA
cannot reduce its payment for power that it purchases from us below a certain
minimum amount. MEA will be required to pay demand charges based upon the
highest post-1985 historical coincident peak on the MEA system. Therefore, if
MEA converts to net-requirements service, we will continue to recover all or
substantially all of the fixed costs assigned to it. 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. We do not expect that the Alaska legislature will pass a law granting
retail competition in the foreseeable future and 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 a discussion of material pending
litigation between MEA and us, see "Legal Proceedings."
Our contract for the benefit of HEA obligates HEA (through AEG&T) to
take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per
year. The HEA contract includes limitations on the costs that may be included in
our rates charged to it. The HEA contract expires on January 1, 2014. HEA'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 HEA. 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 HEA, we will sell energy to AEG&T equal to HEA'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 HEA needs in excess of the sum of our contract demand plus HEA's
share of energy from the Bradley Lake project. The dispatch agreement will
terminate in 2014 when our power supply contract for the benefit of HEA
terminates.
On August 24, 2001, Alaska Electric and Energy Cooperative, Inc. (AEEC)
and AEG&T filed an Application to Transfer Certificate of Public Convenience and
Necessity No. 345 to serve as the wholesale power supplier of HEA, instead of
AEG&T. HEA is the sole member of AEEC. The RCA was requested to act on the
transfer prior to the end of 2001; however, the application includes the
expectation that our power sales agreement will be assigned to AEEC and the
Nikiski dispatch agreement will be assigned to HEA. HEA has been requested to
meet with us in that regard.
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
thereby reduces the demand charge by 1/3 (approximately $350,000 annually). This
agreement was originally set to expire September 1, 2001, but we negotiated an
amendment to the agreement that extended 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. The RCA conditionally approved the
extension on April 19, 2001, with an effective date of September 11, 2001. The
RCA required an amendment to the contract to include an option to re-negotiate
the terms of the contract if rates are adjusted by the general rate case we
filed in July 2001. Seward has three choices within sixty days of the final
order of the RCA in that general rate case. The choices are to continue the
contract using the rate methodology adopted in the case, negotiate a new
contract or give notice of termination effective twelve months from the
effective date of the final order of the RCA.
Economy Customers
Since 1988, we have sold economy (nonfirm) 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 it would otherwise generate
itself or purchase from other sources. We purchased gas 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 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. 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, in which we are assured of
selling 300 million kWh of GVEA's load and an additional 80% of the excess over
450 million kWh of energy that GVEA purchases each year if we are capable of
producing that energy. The remaining energy purchases by GVEA are made through
the "Economy Energy Spot Market." Neither we nor any other seller enjoys a
contractual priority in making such sales. GVEA makes purchases from the seller
offering the lowest competitive price. One of those sellers, AML&P, is expected
to dominate sales in the Economy Energy Spot Market for the immediate future,
partly because AML&P prices its gas at a rate less than the rate on which we
rely in making such sales (based on Marathon gas).
Load Forecasts
The following table sets forth our projected load forecasts for the
next five years:
Load (MWh) 2002 2003 2004 2005 2006
---------- ---- ---- ---- ---- ----
Retail............ 1,131,666 1,157,509 1,179,497 1,197,027 1,206,932
Wholesale......... 1,128,347 1,163,645 1,196,738 1,225,912 1,248,269
Economy........... 160,000 160,000 160,000 160,000 160,000
Losses............ 126,104 129,329 132,184 134,562 136,118
--------- --------- --------- --------- ---------
Total.......... 2,546,117 2,610,483 2,668,419 2,717,501 2,751,319
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 a rate of 2.1%
and wholesale sales at a rate of 3.2%.
Item 2 - Properties
General
We have 527 megawatts of installed capacity consisting of 17 generating
units at five power plants. These include 381.2 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 Power Plant in Anchorage; and 20.0 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 Project generating units that we
jointly own 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 HEA 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
Power Plant in Anchorage. We also lease warehouse space for some generation,
transmission and distribution inventory (including a small amount of office
space).
Generation Assets
We own the land and improvements comprising our generating facilities
at Beluga and International facilities. We also own all improvements comprising
our generating plant at Bernice Lake, located on land leased from HEA. The
Bernice Lake ground lease expires in 2011. 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 and which expires in 2007. We are in the process of
reviewing the lease. 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
have a combined capacity of 342.0 MWh and meet most of our load. All other units
are used principally as reserve. While the Beluga turbine-generators have been
in service for many years, they have been maintained in good working order with
periodic upgrades. Beluga unit 3 had a major overhaul in 1996 and was recently
placed back into service after another major overhaul. Beluga unit 5 received a
major overhaul in 1997 and is scheduled for another overhaul in the fall of
2002. Beluga unit 6 was "repowered" in 2000 adding in excess of 25 years to its
life. Beluga unit 7 was "repowered" in 2001. Beluga unit 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 2001 and
percentages of contribution and other historical information for all Chugach
generation units.
Percent of Percent of
Commercial Operation Rating Run hours total time
Facility Date Nomenclature (MW)(1) (2001) generation available
-------- ---- ------------ ------- ------ ---------- ---------
Beluga Power
Plant (3)
1 1968 GE Frame 5 19.6 807.8 .42 98.3
2 1968 GE Frame 5 19.6 881.1 .40 99.8
3 1972 GE Frame 7 64.8 7403.6 19.61 94.5
5 1975 GE Frame 7 68.7 6028.9 15.80 86.3
6 1975 BB 11D-4NM 82.5 7711.4 28.25 88.5
7 1978 BB 11D-4NM 71.0 4848.1 12.94 62.8
8 1981 BB DK-21150(2) 55.0 7603.6 13.01 86.8
Bernice Lake
Power Plant
2 1971 GE Frame 5 19.0 0.0 0.00 100
3 1978 GE Frame 5 26.0 4445.3 4.12 87.3
4 1981 GE Frame 5 22.5 2329.8 1.94 99.7
Cooper Lake
Hydroelectric
Plant
1 1960 BB MV 230/10 10.0 4753.3 2.09 57.1
2 1960 BB MV 230/10 10.0 3061.3 1.26 35.7
International
Power Plant
1 1964 GE Frame 5 14.1 144.9 0.06 92.9
2 1965 GE Frame 5 14.1 146.0 0.04 100
3 1969 Westinghouse 191G 18.5 147.2 0.06 100
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 50312.3 100.00
<FN>
(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.
Note: GE = General Electric, BB = Brown Boveri
</FN>
Transmission and Distribution Assets
As of December 31, 2001, our transmission and distribution assets
included 39 substations and 402 miles of transmission lines, 930 miles of
overhead distribution lines and 680 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. As part of our 1997
acquisition of 30% of the Eklutna facility, 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 Indenture, are pledged as
collateral for the long-term obligations until retirement of the 1991 Series A
Bond and subsequent institution of the Amended and Restated Indenture. On the
release date, the Bonds will become general unsecured and unsubordinated
obligations. Under the Amended Indenture, Chugach is prohibited from creating or
permitting to exist any mortgage, lien, pledge, security interest or encumbrance
on our properties and assets (other than those arising by operation of law) to
secure the repayment of borrowed money or the obligation to pay the deferred
purchase price of property unless we equally and ratably secure all bonds
subject to the Amended Indenture, except that we may incur secured indebtedness
in an amount not to exceed $5 million or enter into sale and leaseback or
similar agreements.
In addition to the lien of the 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 (AML&P, HEA and MEA (through AEG&T), GVEA and Seward
and us). 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 commercial operation of the facility (September, 1991) or when
the revenue bond principal is repaid, whichever is the longer. We believe that
our maximum annual liability for our take-or-pay obligations is approximately
$4.1 million. We believe that so long as this project produces power taken by us
for our use that this expense will be recoverable through a fuel surcharge. The
share of Bradley Lake indebtedness for which we are responsible is approximately
$43.9 million. 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 the
defaulting 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
HEA's share of the Bradley Lake project through AEG&T 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 HEA. 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 also owns 17% of
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 2001, 94% of our power was generated from gas, and 77% 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 2001 provided approximately equal shares of
the Beluga gas. We have approximately 353 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 10 to 15 years. The deliverability
requirements under the Beluga Field producers 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) ($2.3422 per
thousand cubic feet (MCF) on January 1, 2002), 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) ($2.9278 per MCF on January 1,
2002), 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, 2002, exclusive of taxes, was
$2.6616 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, International and Nikiski 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. The terms of the Marathon contract also gave Marathon a right
to provide additional volumes in the period following depletion of the initial
commitment of 215 BCF. On June 13, 2001, we were notified that Marathon will not
commit to supply any additional volumes.
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. ENSTAR is obligated to supply all of the gas we require
at a price approved by the RCA. There is a monthly minimum bill of $10,465 but
no requirement to actually use any gas at the International Power Plant.
Environmental Matters
General
Our operations are subject to certain federal, state and local
environmental laws and regulations, which seek to limit to air, water and other
pollution and regulate hazardous or toxic waste disposal. While we monitor these
laws and regulations to ensure compliance, they frequently change and often
become more restrictive. When this occurs, the costs of our compliance generally
increase.
We include costs associated with environmental compliance in both our
operating and capital budgets. We accrue for costs associated with environmental
remediation obligations when those costs are probable and reasonably estimable.
We do not anticipate that environmental related expenditures will have a
material effect on our results of operations or financial condition. We cannot,
however, predict the nature, extent or cost of new laws or regulations relating
to environmental matters.
The Clean Air Act and Environmental Protection Agency (EPA) regulations
under the act (the "Clean Air Act") establish ambient air quality standards and
limit the emission of many air pollutants. Some Clean Air Act programs that
regulate electric utilities, notably the Title IV "acid rain" requirements, do
not apply to facilities located in Alaska. The EPA's anticipated regulations to
limit mercury emissions from fossil-fired steam-electric generating facilities,
are not expected to materially impact Chugach because our thermal power plants
burn exclusively natural gas.
New Clean Air Act regulations impacting electric utilities may result
from future events or may result from new regulatory programs that may be
established to address problems such as global warming. While we cannot predict
whether any new regulation would occur or its limitation, it is possible that
new laws or regulations could increase our capital and operating costs. We have
obtained or applied for all Clean Air Act permits currently required for the
operation of our generating facilities, and we are not aware of any future
requirements that will materially impact our financial condition.
We are subject to numerous other environmental statutes including the
Clean Water Act, the Resource Conservation and Recovery Act, the Toxic
Substances Control Act, the Endangered Species Act, and the Comprehensive
Environmental Response, Compensation and Liability Act and to the regulations
implementing these statutes. We do not believe that compliance with these
statutes and regulations to date has had a material impact on our financial
condition or results of operation. However, new laws or regulations,
implementation of final regulations or changes in or new interpretations of
these laws or regulations could result in significant additional capital or
operating expenses.
Cooper Lake
The Association discovered polychlorinated biphenyls (PCBs) in paint,
caulk and grease at the Cooper Lake Hydroelectric plant during initial phases of
a turbine overhaul. A Federal Energy Regulatory Commission (FERC) approved plan,
prepared in consultation with the Environmental Protection Agency (EPA), was
implemented to remediate the PCBs in the plant. As a condition of its approval
of the license amendment for the overhaul project, FERC required Chugach to also
investigate the presence of PCBs in Kenai Lake. A sampling plan was developed by
Chugach in consultation with various agencies and approved by FERC. In 2000,
Chugach sampled sediments and fish collected from Kenai Lake and other waters.
While extremely low levels of PCBs were found in some sediment samples taken
near the plant, no pathway from sediment to fish was established. Additional
sediment sampling and analysis in this area is being performed. While the
presence of PCBs in fish did not reveal amounts above background levels, Chugach
has conducted additional sampling and analysis of fish in Kenai Lake and other
waters and is preparing a report to FERC, analyzing the results of the sampling.
Management believes the costs of this work will be recoverable through rates and
therefore will have no material impact on our financial condition or results of
operations. The RCA has issued an order to Chugach generally allowing prudently
incurred remediation costs at Cooper Lake to be recovered through rates,
however, the RCA has not approved the final recovery amount in this matter and
will review these costs as part of the 2000 test year rate case.
Item 3 - Legal Proceedings
Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc.
Superior Court Case No. 3AN-99-8152 Civil
- --------------------------------------------------------------------------------
This action was a claim for a breach of the Tripartite Agreement, which
is the contract governing the parties' relationship for a 25-year period from
1989 through 2014 and governing the Company's sale of power to MEA during that
time. MEA asserted the Company breached that contract by failing to provide a
variety of kinds of information, by failing to properly manage the Company's
long-term debt, and by failing to bring its base rate action to the Joint Rates
Committee before presentation to the RCA. All of MEA's claims have been
dismissed. MEA has indicated that it intends to appeal to the Alaska Supreme
Court, at a minimum, the Superior Court's dismissal of its financial
mismanagement claim.
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 for the years ended December 31:
Balance Sheet Data 2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Plant net:
In service $452,964,686 $427,127,258 $398,544,496 $386,235,421 $393,228,853
Construction work in
Progress 28,887,008 42,027,617 47,257,296 30,405,736 24,664,395
---------- ---------- ---------- ---------- ----------
Electric plant, net 481,851,694 469,154,875 445,801,792 416,641,157 417,893,248
Other assets 93,429,493 70,591,105 72,553,745 64,450,293 67,674,051
---------- ---------- ---------- ---------- ----------
Total assets $575,281,187 $539,745,980 $518,355,537 $481,091,450 $485,567,299
============ ============ ============ ============ ============
Capitalization:
Long-term debt 364,310,000 312,219,945 337,150,295 305,917,699 312,006,501
Equities and margins 131,808,706 128,815,340 122,524,645 114,023,296 109,119,697
----------- ----------- ----------- ----------- -----------
Total capitalization $496,118,706 $441,035,285 $459,674,940 $419,940,995 $421,126,198
============ ============ ============ ============ ============
Summary Operations Data
Operating revenues $178,595,214 $158,541,114 $142,644,327 $141,825,373 $143,947,730
Operating expenses 147,496,721 126,430,273 110,456,886 110,737,441 113,070,990
Interest expense 28,353,487 26,158,769 25,228,001 26,011,392 26,661,510
Amortization of gain on
Refinancing 1,123,973 1,440,479 1,092,620 1,542,723 1,577,149
--------- --------- --------- --------- ---------
Net operating margins 3,868,979 7,392,551 8,052,060 6,619,263 5,792,379
Nonoperating margins 1,670,157 2,287,227 1,615,374 2,111,141 1,762,018
--------- --------- --------- --------- ---------
Assignable margins $5,539,136 $9,679,778 $9,667,434 $8,730,404 $7,554,397
========== ========== ========== ========== ==========
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. These amounts are referred to as "margins." Patronage
capital, the retained margins of our members, constitutes our principal equity.
Times Interest Earned Ratio (TIER). Alaska electric cooperatives
generally set their 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 (excluding capitalized
interest). We manage our business with a view toward achieving a TIER of 1.25 or
greater. We achieved TIERs for the past five years as follows:
Year TIER
---- ----
2001 1.20
2000 1.39
1999 1.40
1998 1.35
1997 1.30
Rate Regulation and Rates. Our rates are made up of two components:
"base rates" and "fuel surcharge rates." "Base rates" are composed of fixed and
variable charges in connection with the generation and transmission of
electricity. Although a base fuel and purchased power component is included in
base rates, they consist primarily of costs other than fuel and purchased power
costs. "Fuel surcharge" rates take into account the rise and fall of fuel and
purchased power costs and ensure collection of fuel and purchased power costs
above the base component included in the base energy rate. The RCA approves the
amounts 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 an order of the
RCA following a general rate case, where we propose a rate increase or decrease
for each class of customer based on our costs to service those classes during a
recent year referred to as a test year. While this process typically takes nine
months to one year, the RCA may authorize, after a notice period, rate changes
on an interim and refundable basis. In addition, the RCA has been willing to
open limited reviews of rate cases to resolve specific issues from which
expeditious decisions can often be generated.
We filed a general rate case in July 2001, requesting a permanent base
rate increase of 6.5%, and an interim base rate increase of 4%. On September 5,
2001, the RCA granted a 1.6% interim increase effective September 14, 2001. We
filed a petition for reconsideration and on October 25, 2001, the RCA approved
an interim base rate increase of 3.97%. The additional rate increase was
implemented on November 1, 2001. The 3.97% interim base rate increase was
anticipated to result in approximately $0.7 million in additional revenue in
2001 compared to previous permanent base rates, or $4.1 million on an annualized
basis. The interim base rate increase is based on a normalized, or adjusted for
recurring expenses, test year and a system ratemaking TIER of 1.35.
The requested permanent base rate increase of 6.5%, if approved by the
RCA, is anticipated to result in $7.5 million in additional revenue each year,
or approximately $3.4 million more than the interim base rate increase approved
by the RCA, which became effective on November 1, 2001, and margins of $10.8
million for 2002 at the base rate submitted. The requested permanent base rate
increase is scheduled for a hearing before the RCA in August 2002.
Prior to 2001, our base rates to our retail customers had not increased
since 1994. As part of a settlement of disputes over rate adjustments with our
wholesale customers (the "Settlement Agreement"), we agreed that our base rate
for wholesale customers would not exceed 1995 levels at least through 1999 and
could be reduced if those rates provide returns significantly higher than those
specified in the settlement. As discussed below, we have granted refunds for
rates based on our 1996 costs. The RCA issued an order on February 27, 2001,
that no rate reduction or refunds were required based on our 1997 test year
costs. According to an order issued by the RCA on March 15, 2002, no rate
reduction or refunds were required based on our 1998 test year costs. Parties
have until April 1, 2002 to file a request for reconsideration.
Our base rate changes, excluding fuel surcharges, for retail and
wholesale classes, for the years 1999 through 2001 were as follows:
2001 2000 1999
---- ---- ----
Retail* 1.6% 0.0% 0.0%
Wholesale:
HEA 1.6% (0.7%) (0.3%)
MEA 1.6% (0.8%) (3.8%)
Seward 0.0% 0.0% 0.0%
* The 2001 base rate increase was not applied to small general service or
lighting customer classes.
The rate reductions shown in the table for Matanuska Electric
Association (MEA) and Homer Electric Association (HEA) in 1999 and 2000 relate
to our filing under the Settlement Agreement of our cost of service for 1996.
Our calculations 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 $2.7 million at December 31, 1999. Early in 2000, we issued
additional refunds of $86,132 to HEA and $1.8 million to MEA that represented
uncontested amounts owed to them under the Settlement Agreement. 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 HEA 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 RCA issued an order for the 1997 test year that did not reduce
wholesale rates or require refunds under the Settlement Agreement. According to
an order issued by the RCA on March 15, 2002, no rate reduction or refunds were
required based on our 1998 test year costs. Parties have until April 1, 2002 to
file a request for reconsideration.
The rate reduction to the City of Seward (Seward) in 1998 was the
result of a contract re-negotiation through which Seward moved from being a firm
customer to an interruptible customer. The rate reduction reflects a negotiated
reduction of rates for Seward since the Seward load can be interrupted.
Fuel Surcharge. We pass fuel and purchased power costs above base
amounts included in the base rate directly to our wholesale and retail customers
through the fuel surcharge. Changes in fuel and purchase power costs are
primarily due to fuel price adjustment mechanisms in our gas supply contracts
based on natural gas, crude oil and fuel oil indexed price changes. We pass
these costs directly to our retail and wholesale customers. The fuel surcharge
is approved on a quarterly basis by the RCA. There are no limitations on the
number or amount of 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 refunds of approximately $1.2 million because of
alleged over-collection of fuel surcharges in 1995, 1996 and 1997. We appealed
that finding to the Superior Court, which overturned it. MEA appealed that
decision to the Alaska Supreme Court and the RCA filed an amicus brief generally
supporting the MEA position. A hearing before the court was held October 17,
2001 and a decision is pending.
Year ended December 31, 2001 compared to the years ended December 31, 2000 and
1999 Margins
Our margins for the years ended December 31, 2001, 2000 and 1999, were
as follows:
2001 2000 1999
---- ---- ----
Net Operating Margins $3,868,979 $7,392,551 $ 8,052,060
Nonoperating Margins $1,670,157 $2,287,227 $ 1,615,374
---------- ---------- -----------
Assignable Margins $5,539,136 $9,679,778 $ 9,667,434
========== ========== ===========
The decrease in net operating margins and assignable margins is
primarily attributable to an increase in depreciation due to a substantial
increase in plant in the fourth quarter of 2000 related to the Beluga unit 6
re-powering, increased interest expense due to the issuance of $150 million of
long-term debt in the second quarter of 2001, and a decrease in capitalized
interest charged to construction. Another factor in the margin decrease was that
our requested interim rate increase did not become effective until September 14,
2001.
Nonoperating margins include interest income, allowance for funds used
during construction, capital credits and patronage capital allocations.
Nonoperating margins decreased in 2001 over 2000 by $617,000 or 27%. This was
due to decreased allocations of patronage capital from CoBank and the loss
associated with the sale of the Internet segment. 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.
Revenues
Operating revenues include sales of electric energy to retail,
wholesale and economy energy customers and other miscellaneous revenues. In
2001, operating revenues were $20 million, or 13% higher than in 2000 due to
increased kWh sales and increased fuel prices, resulting in increased revenue
collected through the fuel surcharge mechanism. This was offset by decreased
economy energy sales to Golden Valley Electric Association (GVEA) and decreased
revenue generated by the Internet segment. In 2000, operating revenues were $159
million, which was 11% higher than in 1999 primarily due to increased sales of
economy energy to 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. The major components of our operating revenue for the year ended
December 31, 2001 and 2000, were as follows:
2001 2000 1999
---- ---- ----
Retail $112,026,122 $98,536,690 $94,057,713
Wholesale
HEA 24,260,072 19,060,244 17,357,727
MEA 33,706,678 27,252,051 25,063,734
Seward 2,816,970 2,369,550 2,168,982
Economy energy 3,354,719 7,820,998 1,864,873
Other 2,430,653 3,501,581 2,131,298
--------- --------- ---------
Total revenue $178,595,214 $158,541,114 $142,644,327
============ ============ ============
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 2001, 2000, and 1999,
economy sales to GVEA constituted approximately 1.90%, 5.00%, and 0.79%,
respectively, of our sales revenues. The decrease in economy sales in 2001 from
2000 was due to increased fuel prices, which made it more economical for GVEA to
produce their own power, rather than purchase it from Chugach. 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 clean-coal 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, 2001, 2000 and 1999 were as follows:
2001 2000 1999
---- ---- ----
Power production 68,527,902 52,726,374 40,301,607
Purchased power 14,717,318 9,152,248 8,581,979
Transmission 3,545,707 3,828,630 3,813,438
Distribution 10,417,736 9,774,860 9,400,618
Consumer accounts 5,121,394 5,275,455 4,387,421
Sales expense 495,523 1,112,804 1,227,908
Administrative, general and other 19,574,476 21,343,393 22,892,479
Depreciation 25,096,665 23,216,509 19,851,436
---------- ---------- ----------
Total operating expenses 147,496,721 126,430,273 110,456,886
=========== =========== ===========
Power production expense increased in 2001 from 2000 by $15.8 million,
or 30%, due primarily to an increase in fuel expense from $42.5 million in 2000
to $56.1 million in 2001, as well as the use of less efficient units in order to
meet demand while Beluga unit 6 and unit 7 were unavailable. 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.
Purchased power costs increased by $5.6 million, or 61%, from 2000 to
2001 due to Soldotna #1 power plant being placed back into service under a new
contract at a Nikiski fertilizer plant that requires the Nikiski unit to be run
at full capacity. 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 2000, the limited availability of Beluga 3 and
Beluga 6 units during the summer months and an increase in economy energy
purchases for GVEA.
Transmission expense did not vary materially in 2001 from 2000 or from
1999 to 2000.
Distribution expense increased in 2001 from 2000 by $643,000, or 7%,
due to an increase in trouble calls in the Operations area relating to outages
and damage claims, as well as increased locate activity in Tyonek. 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.
Consumer accounts expense did not vary materially from 2000 to 2001.
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.
Sales expense decreased from 2000 to 2001 by $617,000, or 55%, due to
the sale of the Internet business, as well as a shift in the activities of the
Marketing department from sales activities to customer information activities.
Sales expense did not vary materially from 1999 to 2000. The slight variances
were due to more or less allocated marketing cost resulting from changes in the
number of employees in the marketing department in those years.
Administrative, general and other expense decreased by $1.8 million, or
8%, from 2000 to 2001, due to the sale of the Internet business, which resulted
in a decrease in cost of goods sold and consulting expenses. Administrative,
general and other expense decreased by $1.6 million, or 7%, 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 the takeover
attempt by MEA, the resultant special meeting in 1999 and an update in
allocations of cost related to information services in 2000.
We use the composite method of depreciation. Depreciation expense
increased by $1.9 million, or 8%, from 2000 to 2001, due to the completion of
many projects thereby increasing the level of plant currently being depreciated.
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.
Interest on long-term obligations increased from 2000 to 2001 by $2.1
million, or 9%, due to the public bond offering in April 2001. Interest on
long-term obligations 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). Interest on short-term obligations decreased by $745,000, or 39%,
from 2000 to 2001 due to lower outstanding balances on the lines of credit.
Interest on short-term debt increased from 1999 to 2000 by $912,000, or 91%, due
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. There was a decrease
in interest charged to construction due to a decrease in construction projects
from 2000 to 2001, which was the same reason there was an increase from 1999 to
2000 in this category. Net interest expense includes interest on long-term
obligations and short-term obligations, reduced by interest charged to
construction. The amortization of the gain on refinancing debt offset by the
amortization of losses on refinancing debt and transaction costs resulted in a
reduction to net interest expense of $1.1 million, $1.4 million and $1.1 million
in 2001, 2000 and 1999, respectively.
Patronage Capital (Equity)
Our patronage capital and total equity have shown steady growth. The
following table summarizes our patronage capital and total equity position for
the years ended December 31, 2001, 2000 and 1999:
2001 2000 1999
---- ---- ----
Patronage capital at beginning of year $122,925,253 $117,335,481 $109,622,996
Retirement of capital credits
and estate payments (3,280,015) (4,090,006) (1,954,949)
Assignable margins 5,539,136 9,679,778 9,667,434
Patronage capital at end of year 125,184,374 122,925,253 117,335,481
Other equity 6,624,332 5,890,087 5,189,164
Total equity at end of year $131,808,706 $128,815,340 $122,524,645
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
distributions of these amounts to members, also known as capital credits, 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, 2001, we retired all retail capital credits attributable to
margins earned in periods prior to and including 1985 retail capital credits.
Prior to 2000, wholesale capital credits had been retired on a 10-year cycle
pursuant to an approved capital credit retirement program, which is contained in
the Chugach business plan. 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 million plus 35%
of the aggregate assignable margins earned after December 31, 1990. At December
31, 2001, we were permitted to distribute $4.5 million to our members under the
1991 Indenture under this formula. In December 2001, we distributed $3 million
of patronage capital to our members. The Amended Indenture prohibits us from
making any distributions, payment or retirement of patronage capital to our
customers if an event of default under the Amended Indenture exists. Otherwise,
we may make distributions to our members in each year equal to the lesser of 5%
of our patronage capital or 50% of assignable margins for the prior fiscal year.
This restriction does not apply if, after the distribution, our aggregate
equities and margins as of the end of the immediately preceding fiscal quarter
are equal to at least 30% of our total liabilities and equities and margins.
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
2002 $0 $3,500,000 $3,500,000
2003 0 3,500,000 3,500,000
2004 1,359,000 2,141,000 3,500,000
2005 1,109,000 2,391,000 3,500,000
2006 1,671,000 1,829,000 3,500,000
Sale of a Segment
As of March 6, 2001, with an effective date of March 20, 2001, Chugach
sold the bulk of its internet service provider assets related to dial-up
services (excluding DSL services) to General Communication Incorporated. The
aggregate purchase price was $759,049 at closing, plus an additional amount of
$70,075, which was based on number of subscriber accounts retained during the
ninety-day transition period following closing. These transactions resulted in a
loss of $258,073.
Changes In Financial Condition
Total assets increased by $35.5 million, or 7%, from December 31, 2000,
to December 31, 2001. The increase was primarily due to an increase in electric
plant in service related to the Beluga unit 7 "repower", the Cooper Lake
overhaul, the Supervisory Control and Data Acquisition (SCADA) upgrade, the
International Generating Terminal (IGT) auxiliaries improvement and
miscellaneous distribution projects. Deferred charges increased due to debt
issuance and acquisition costs associated with the April 2001 public bond
offering. There was also an increase in accounts receivable due to wholesale
power bills that were accrued but not paid at December 31, 2001. There was an
increase in fuel cost recovery caused by the under-collection of the fuel
surcharge in the fourth quarter of 2001 and an increase in materials and
supplies caused by the purchase of generation parts needed for unit maintenance
in 2002.
Changes to total liabilities include the increase in long-term
obligations and accrued interest due to the public bond offering in April 2001.
Current installments of long-term obligations increased due to the first
installment of CoBank 5 due in June of 2002. 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. These,
however, were offset by a decrease in notes payable, as well as a decrease in
deferred credits caused by the decrease of the gain on refinancing.
Contractual Obligations and Commercial Commitments
The following are Chugach's contractual and commercial commitments as
of December 31, 2001:
Contractual cash obligations:
Payments Due Per Period
Total 2002 2003-2004 2005-2006 Thereafter
Long-term debt $374,720 $10,410 $1,811 $12,157 $350,342
Short-term debt $11,000 $11,000 $0 $0 $0
Total $385,720 $21,410 $1,811 $12,157 $350,342
Commercial Commitments:
Amount of Commitment
Expiration Per Period
Total 2002 2003-2004 2005-2006 Thereafter
Lines of credit-available * $74 $74 $0 $0 $0
Total $74 $74 $0 $0 $0
*At December 31, 2001, Chugach had $85 million in lines of credit with various
financial institutions, which fund capital requirements, effectively reducing
the available borrowing capacity under these lines of credit to $74 million.
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, 2001, there was no
outstanding balance with CFC. As of December 31, 2001, $11 million was
outstanding under the CoBank line of credit. This line of credit bears interest
at a variable rate, which was 3.75% as of December 31, 2001, and is currently
3.75% as of March 2002.
On April 17, 2001, Chugach issued $150,000,000 of 2001 Series A Bond,
for the purpose of retiring indebtedness outstanding under existing lines of
credit and outstanding bonds, for capital expenditures and for general working
capital. The lines of credit had an aggregate outstanding principal balance of
$55,000,000, as of April 17, 2001, were renewable annually and bore interest at
variable annual rates ranging from 7.55% to 7.80% at April 17, 2001. The
variable-rate bonds retired had an aggregate outstanding principal balance of
$72,500,000, as of April 17, 2001, would have matured in 2002 and bore interest
at a variable rate that was 7.55% on April 17, 2001.
The 2001 Series A Bond will mature on March 15, 2011, and bear interest
at 6.55% per annum. Interest will be paid semi-annually on March 15 and
September 15 of each year commencing on September 15, 2001. The 2001 Series A
Bond is secured by a first lien on substantially all of Chugach's assets. The
first lien will be automatically released when all bonds issued by Chugach prior
to April 1, 2001, cease to be outstanding or their holders consent to conversion
to unsecured status. Thereafter, the 2001 Series A Bond will be an unsecured
obligation, ranking equally with Chugach's other unsecured and unsubordinated
obligations.
On February 1, 2002, Chugach issued a $120,000,000 2002 Series A Bond
and $60,000,000 2002 Series B Bond for the purpose of redeeming $149.3 million
in principal amount of the 1991 Series A Bond due 2022, to pay the redemption
premium on the 1991 Series A Bond due 2022 in the amount of $13.6 million and
for general working capital. On March 15, 2002, all of the remaining 1991 Series
A Bonds due 2022 were redeemed and the final payment on the 1991 Series A Bonds
due 2022 was made. The 2002 Series A Bond will mature on February 1, 2012, and
bear interest at 6.20% per annum. Interest will be paid semi-annually on
February 1 and August 1 of each year commencing on August 1, 2002. Chugach may
not redeem the 2002 Series A Bond prior to maturity.
The 2002 Series B Bond (the "Auction Rate Bond") will mature on
February 1, 2012. The Auction Rate Bond will bear interest from February 1, 2002
through February 27, 2002, at 1.97% and afterwards, will initially bear interest
at the rate set for 28-day auction periods. The initial auction date was
February 27, 2002. The applicable interest rate for any 28-day auction period
will be the term rate established by the auction agent based on the terms of the
auction. The Auction Rate Bond may be converted, in our discretion and in some
cases subject to the consent of the bond insurer, to a daily, seven-day, 35-day,
three-month or a semi-annual period or a flexible auction period. The Auction
Rate Bond is subject to optional and mandatory redemption and to mandatory
tender for purchase prior to maturity in the manner and at the times described
herein. Bankers Trust Company will act as the auction agent and J.P. Morgan
Securities Inc., will act as the initial broker-dealer for the Auction Rate
Bond.
Payment of the 2002 Series A Bond and the Auction Rate Bond (collectively
the "Bonds") initially will be secured by a first lien on substantially all of
Chugach's tangible and some intangible properties. The first lien will be
automatically released when all bonds issued by Chugach prior to April 1, 2001,
cease to be outstanding or their holders consent to the release of the lien.
After that time, the Bonds will be unsecured obligations; ranking equally with
our other unsecured and unsubordinated obligations. In addition, we will be
limited in our ability to secure obligations for borrowed money or the deferred
purchase price of property after that time unless Chugach equally and ratably
secures our outstanding indebtedness subject to the Indenture governing the
Bonds.
Principal maturities and sinking fund payments of our outstanding
indebtedness at December 31, 2001 are set forth below:
Year Ending Sinking Fund Principal maturities
December 31 Requirement Total
2002 $5,232,000 $5,177,945 $10,409,945
2003 0 865,821 865,821
2004 0 945,000 945,000
2005 0 11,031,393 11,031,393
2006 0 1,125,687 1,125,687
Thereafter 299,310,000 51,032,099 350,342,099
$304,542,000 $70,177,945 $374,719,945
During 2001 we spent approximately $36.4 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 2002 through 2006:
2002 $33.2 million
2003 $32.8 million
2004 $42.3 million
2005 $24.7 million
2006 $38.4 million
The anticipated large increase in capital expenditures in 2004
represents the construction of a transmission line from the International Power
Plant to University Station via new South Anchorage Bulk Substation, the Wind
Turbine capital project and an overhaul of Beluga unit 6.
We expect that cash flows from operations and external funding sources
will be sufficient to cover operational and capital funding requirements in 2002
and thereafter.
Critical Accounting Policies
The preparation of financial statements in conformity with Generally
Accepted Accounting Principles (GAAP) requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and reported amounts of assets and liabilities in the financial statements. The
following areas represent those that management believes are particularly
important to the financial statements and that require the use of estimates and
assumptions to describe matters that are inherently uncertain.
FERC Accounting
Chugach prepares its financial statements in accordance with GAAP and
in conformity with the FERC's uniform system of accounts.
Cost Basis Regulation
Chugach is subject to regulation by the RCA. The rates that are charged
by CEA to its customers are based upon cost basis regulation reviewed and
approved by this regulatory commission. Under the authority of this commission,
CEA has recorded certain regulatory assets in the amount of $21.5 million and
regulatory liabilities in the amount of $15.6 million as of December 31, 2001.
If CEA's rates were no longer based upon cost basis or the probability of future
collection in rates, regulation, the assets and liabilities would be written off
to margins.
Financial Instruments and Hedging
CEA uses U.S. Treasury forward rate lock agreements to hedge expected
interest rates on probable debt. The Association accounted for the agreements
under SFAS 80 and 71 through December 31, 2000, and SFAS 133, 138 and 71
subsequent to that date. Gains or losses are treated as regulatory assets or
liabilities upon settlement. Accounting for derivatives continue to evolve
through guidance issued by the Derivatives Implementation Group (DIG) of the
Financial Accounting Standards Board. To the extent that changes by the DIG
modify current guidance, the accounting treatment for derivatives may change.
Recent Accounting Pronouncements
Chugach was required to adopt SFAS 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities, an Amendment of
FASB Statement No. 133, effective January 1, 2001. This new standard requires
all derivative financial instruments to be reflected on the balance sheet. The
adoption resulted in Chugach establishing a liability for the settlement of U.S.
Treasury Rate Lock Agreements.
In July 2001 the Financial Accounting Standards Board issued Statement
141, Business Combinations, and Statement 142, Goodwill and Other Intangible
Assets. Statement 141 requires that the purchase method of accounting be used
for all business combinations initiated or completed after June 30, 2001.
Statement 142 will require that goodwill and intangible assets with indefinite
useful lives no longer be amortized, but instead tested for impairment at least
annually. The provisions of Statement 142 are required to be applied starting
with fiscal years beginning after December 15, 2001. Management believes the
adoption of Statement 141 and 142 will have no impact on our financial
statements.
In August 2001 the Financial Accounting Standards Board issued
Statement 143, Accounting for Asset Retirement Obligations. Statement 143
requires an enterprise to record the fair value of an asset retirement
obligation as a liability in the period in which it incurs a legal obligation
associated with the retirement of tangible long-lived assets and an increase to
the carrying amount of the related long-lived asset, which is depreciated over
the life of the asset. Enterprises are required to adopt Statement 143 for
fiscal years beginning after June 15, 2002. Management believes the adoption of
Statement 143 will have no impact on our financial statements.
In October 2001 the Financial Accounting Standards Board issued
Statement 144, Accounting for the Impairment or Disposal of Long-Lived Assets.
Statement 144 addresses financial accounting and reporting for the impairment or
disposal of long-lived assets. While Statement 144 supersedes FASB Statement
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of, it retains many of the fundamental provisions of that
Statement, and broadens the presentation of discontinued operations to include
more disposal transactions. Statement 144 also supersedes the accounting and
reporting provisions of Accounting Principles Board (APB) Opinion 30, Reporting
the Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions, for the disposal of a segment of a business. However, it retains
the requirement in Opinion 30 to report separately discontinued operations and
extends that reporting to a component of an entity that either has been disposed
of or is classified as held for sale. Statement 144 is effective for fiscal
years beginning after December 15, 2001, and interim periods within those fiscal
years. Management believes the adoption of Statement 144 will have no impact on
our financial statements.
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, 2001, all of our 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, 2001, and 2000:
2001
Fair
Total Debt* 2002 2003 2004 2005 2006 Thereafter Total Value
- ----------- ---- ---- ---- ---- ---- ---------- ----- -----
Fixed rate $10,410 $866 $945 $11,031 $1,126 $350,342 $374,720 $390,320
Average
interest rate 6.90% 5.60% 5.60% 7.56% 5.60% 7.52% 7.48%
Variable rate $11,000 $0 $0 $0 $0 $0 $11,000 $11,000
Average
interest rate 3.75% -- -- -- -- -- 3.75%
<FN>
* Includes current portion
</FN>
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%
<FN>
* Includes current portion
</FN>
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 $110,000, based on $11 million of variable debt outstanding at
December 31, 2001. The CoBank and CFC lines of credit, under which we currently
have $11 million in short-term debt outstanding, bear interest at variable
rates.
As of December 31, 2001, the aggregate principal amount of outstanding
1991 Series A Bond due 2022 was $149,310,000. In May 2001, we reacquired $10
million of our Series A 2022 Bond for $11.2 million, which included accrued
interest and premium. On December 10, 2001, we reacquired $5 million of our
Series A 2022 Bonds for $5.7 million, which included accrued interest and
premium. The 1991 Series A Bonds due 2022 were not subject to redemption until
March 15, 2002, and all outstanding 1991 Series A Bonds due 2022 were redeemed
on that date.
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 agreement with Lehman Brothers Financial Products Inc. (Lehman
Brothers) in March 1999. The treasury rate-lock agreement has a settlement date
of February 15, 2002. On May 11, 2001, we terminated the $18.7 million U.S.
Treasury portion of the treasury rate-lock agreement in receipt of payment of
$10,000 by Lehman Brothers. On December 7, 2001, we terminated 50%, $98.0
million, of the 10-year U.S. Treasury portion of the treasury rate-lock
agreement for a settlement payment of $4 million to Lehman Brothers. We settled
the remaining 50% of the treasury rate-lock agreement for $3 million on December
19, 2001. The settlement payments will be accounted for as a regulatory asset.
We believe the regulatory asset will be recovered through rates. On January 14,
2002, Chugach entered into an 18-day rate lock agreement with JP Morgan on the
$120 million 10-year term bond of the proposed 2002 financing based on the
10-year treasury issued August 15, 2001, that was trading at 4.877%. That rate,
along with a 4.1 basis point fee, set a benchmark rate for the transaction at
4.918%. Chugach terminated the rate lock on February 1, 2002, which generated a
payment to Chugach for $1.2 million.
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.
Item 8 -Financial Statements and Supplementary Data
December 31, 2001 and 2000
Independent Auditors' Report
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association,
Inc. (Association) as of December 31, 2001 and 2000, 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, 2001. These financial statements are
the responsibility of the Association's management. Our responsibility is to
express an opinion on these financial statements 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
the 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, 2001 and 2000, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2001 in conformity with accounting principles generally accepted in the United
States of America.
/s/ KPMG LLP
March 1, 2002
Anchorage, Alaska
Chugach Electric Association, Inc.
Balance Sheets
December 31, 2001 and 2000
Assets 2001 2000
------ ---- ----
Utility plant (notes 2, 6, 12 and 13):
Electric plant in service $714,317,863 $687,127,130
Construction work in progress 28,887,008 42,027,617
---------- ----------
743,204,871 729,154,747
Less accumulated depreciation 261,353,177 259,999,872
----------- -----------
Net utility plant 481,851,694 469,154,875
Other property and investments, at cost:
Nonutility property 3,550 443,555
Investments in associated organizations (note 3) 10,485,186 9,857,153
---------- ---------
10,488,736 10,300,708
Current assets:
Cash and cash equivalents, including repurchase agreements of $5,520,275
in 2001 and $3,905,283 in 2000
3,814,767 1,695,162
Cash-restricted construction funds 517,871 378,848
Special deposits 222,163 212,163
Accounts receivable, less provision for doubtful accounts of $318,757
in 2001 and $441,933 in 2000 22,302,400 19,200,912
Fuel cost recovery 3,591,963 2,915,733
Materials and supplies 22,822,003 15,357,198
Prepayments 627,544 755,276
Other current assets 335,753 332,246
------- -------
Total current assets 54,234,464 40,847,538
Deferred charges (notes 9 and 14) 28,706,293 19,442,859
---------- ----------
$575,281,187 $539,745,980
<FN>
See accompanying notes to financial statements.
</FN>
Chugach Electric Association, Inc.
Balance Sheets, Continued
December 31, 2001 and 2000
Liabilities & Equities 2001 2000
---------------------- ---- ----
Equities and margins (note 5):
Memberships $1,059,098 $1,009,663
Patronage capital (note 4) 125,184,374 122,925,253
Other (note 5) 5,565,234 4,880,424
--------- ---------
131,808,706 128,815,340
Long-term obligations, excluding current installments (notes 6, 7 and 18):
2001 Series A Bonds payable 150,000,000 0
First Mortgage (1991 Series A) Bonds payable 149,310,000 169,542,000
National Bank for Cooperatives Bonds payable 65,000,000 142,677,945
---------- -----------
364,310,000 312,219,945
Current liabilities:
Current installments of long-term obligations (notes 6 and 7) 10,409,945 6,430,350
Short-term obligations (note 6) 11,000,000 40,000,000
Accounts payable 11,012,905 9,493,875
Consumer deposits 1,603,691 1,324,213
Accrued interest 7,378,058 5,861,390
Salaries, wages and benefits 4,844,819 4,586,407
Fuel 11,565,117 8,154,559
Other current liabilities 1,900,155 1,434,562
--------- ---------
Total current liabilities 59,714,690 77,285,356
Deferred credits (note 11) 19,447,791 21,425,339
---------- ----------
$575,281,187 $539,745,980
<FN>
See accompanying notes to financial statements.
</FN>
Chugach Electric Association, Inc.
Statements of Revenues, Expenses and Patronage Capital
Years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Operating revenues $178,595,214 $158,541,114 $142,644,327
Operating expenses:
Power production 68,527,902 52,726,374 40,301,607
Purchased power 14,717,318 9,152,248 8,581,979
Transmission 3,545,707 3,828,630 3,813,438
Distribution 10,417,736 9,774,860 9,400,618
Consumer accounts 5,121,394 5,275,455 4,387,421
Sales expense 495,523 1,112,804 1,227,908
Administrative, general and other 19,574,476 21,343,393 22,892,479
Depreciation 25,096,665 23,216,509 19,851,436
---------- ----------- ----------
Total operating expenses 147,496,721 126,430,273 110,456,886
Interest expense:
On long-term obligations 27,128,662 24,987,033 24,137,593
Charged to construction - credit (1,063,643) (2,178,425) (1,000,246)
On short-term obligations 1,164,495 1,909,682 998,034
--------- ---------- -------
Net interest expense 27,229,514 24,718,290 24,135,381
---------- ---------- ----------
Net operating margins 3,868,979 7,392,551 8,052,060
Nonoperating margins:
Interest income 679,640 703,807 592,208
Other 1,236,907 1,615,161 1,003,029
Property gain (loss) (246,390) (31,741) 20,137
--------- --------- ------
Assignable margins 5,539,136 9,679,778 9,667,434
Patronage capital at beginning of year 122,925,253 117,335,481 109,622,996
Retirement of capital credits and estate payments (note 4) (3,280,015) (4,090,006) (1,954,949)
----------- ----------- -----------
Patronage capital at end of year $125,184,374 $122,925,253 $117,335,481
============ ============ ============
<FN>
See accompanying notes to financial statements.
</FN>
Chugach Electric Association, Inc.
Statements of Cash Flows
Years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Operating activities:
Assignable margins $5,539,136 $9,679,778 $9,667,434
Adjustments to reconcile assignable margins to net cash
provided by operating activities:
Depreciation and amortization 30,265,821 27,575,408 23,563,805
Capitalization of interest (1,370,319) (340,838) (151,474)
Property (gains) losses, net (246,390) (31,741) 20,137
Other (19,169) (1,155) (221)
Changes in assets and liabilities:
(Increase) decrease in assets:
Special deposits (10,000) (29,999) (61,000)
Accounts receivable (3,101,488) (1,469,918) (1,049,512)
Fuel cost recovery (676,230) (2,734,978) 381,029
Prepayments 127,732 106,671 55,434
Materials and supplies (7,464,805) 1,822,938 (1,216,702)
Deferred charges (13,761,107) (1,231,531) (14,179,418)
Other assets (3,507) 9,456 7,328
Increase (decrease) in liabilities:
Accounts payable 1,519,030 (14,976) 670,093
Accrued interest 1,516,668 (204,724) (656,211)
Deferred credits (1,584,906) (3,638,491) (2,973,944)
Consumer deposits 279,478 264,536 66,061
Other liabilities 4,134,563 3,213,198 524,833
--------- --------- -----------
Total adjustments 9,605,371 23,293,856 5,000,238
--------- ---------- -----------
Net cash provided by operating activities 15,144,507 32,973,634 14,667,672
Investing activities:
Extension and replacement of plant (36,408,253) (46,730,043) (41,884,723)
Increase in investments in associated organizations (608,864) (909,137) (590,276)
--------- ------------ ------------
Net cash used in investing activities (37,017,117) (47,639,180) (42,474,999)
Financing activities:
Transfer of restricted construction funds (139,023) 159,556 (361,038)
Proceeds from short-term borrowings, net (29,000,000) 40,000,000 0
Proceeds from long-term obligations 150,000,000 0 72,500,000
Repayments of long-term obligations (93,930,350) (24,872,405) (40,983,801)
Memberships and donations received 734,245 700,923 788,865
Retirement of patronage capital (3,280,015) (4,090,006) (1,954,949)
Net receipts (refunds) of consumer advances for construction (392,642) 352,610 (384,294)
--------- --------- ---------
Net cash provided by financing activities 23,992,215 12,250,678 29,604,783
Net change in cash and cash equivalents 2,119,605 (2,414,868) 1,797,456
Cash and cash equivalents at beginning of year $1,695,162 $4,110,030 $ 2,312,574
---------- ---------- -----------
Cash and cash equivalents at end of year $3,814,767 $1,695,162 $4,110,030
========== ========== ==========
Supplemental disclosure of cash flow information
Interest expense paid, net of amounts capitalized $25,712,846 $24,917,014 $24,791,592
=========== =========== ===========
<FN>
See accompanying notes to financial statements.
</FN>
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2001 and 2000
(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 (HEA) and the City of Seward (Seward). Our members are the
consumers of the electricity sold.
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).
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 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 members on the
basis of patronage. This patronage capital constitutes the principal
equity of the Association.
Reclassifications
Certain reclassifications have been made to the 1999 and 2000 financial
statements to conform to the 2001 presentation.
Plant Additions and Retirements
Additions to electric plant in service are recorded at original cost of
contracted services, direct labor and materials, indirect overhead
charges and capitalized interest. 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. Renewals and betterments are
capitalized, while maintenance and repairs are charged to expense as
incurred.
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 according to
existing gas supply contracts.
Chugach entered into a settlement agreement with MEA and HEA in 1996. The
settlement agreement was designed to resolve a number of ratemaking
disputes and assure MEA and HEA 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 Agreement 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
HEA 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 HEA 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 RCA issued an order for the 1997 test year that did not reduce
wholesale rates or require refunds under the Settlement Agreement. The
1998 test year hearing has been completed but an order from the RCA has
not yet been issued. Management believes that no rate reduction or refund
will be required based on the 1998 test year. No additional test years
remain to be reviewed under the Settlement Agreement.
Chugach filed a general rate case on July 10, 2001, based on the 2000
test year, requesting a permanent base rate increase of 6.5%, and an
interim base rate increase of 4.0%. On September 5, 2001, the RCA granted
a 1.6% interim increase effective September 14, 2001. We filed a petition
for reconsideration and on October 25, 2001, the RCA approved an interim
base rate increase of 3.97%. The additional rate increase was implemented
on November 1, 2001. The 3.97% interim base rate increase is anticipated
to result in approximately $4.1 million additional revenue on an
annualized basis. The interim and permanent rate increases are subject to
final approval by the RCA after a hearing process. If the RCA does not
agree with the interim increase, Chugach may be required to refund a
portion of the increase. Management believes it is unlikely any of the
interim increase will have to be refunded.
In this filing, Chugach proposed that margins be calculated using a rate
base/rate of return methodology rather than the TIER methodology
previously used. Under this methodology, we can assign different rates of
return to our various business functions, such as generation,
transmission and distribution, in order to recover appropriate risk
premiums for each individual function. In addition, the change in
methodology allows us to more efficiently allocate our cost of funds. The
resultant system TIER would be 1.38 based on the proposed capital
structure contained in that filing. We do not believe that our request to
change from the TIER-based methodology to the return-on-rate-base
methodology will have any material adverse effect on future ratemaking or
on our ability to service our outstanding indebtedness.
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 expired on September 1, 2001. The parties
negotiated and executed an Amendment, extending the term of the contract
to January 31, 2006, which was approved by the RCA July 9, 2001.
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,
in accordance with Chugach's request, 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. In
accordance with SFAS 71, the Association's financial statements reflect
regulatory assets and liabilities. Continued accounting under SFAS 71
required certain criteria be met. Management believes the Association's
operations currently satisfy these criteria. However, if events or
circumstances should change so the criteria are not met, the write off of
regulatory assets and liabilities could have a material effect on the
financial position and results of operations.
Deferred credits, representing regulatory liabilities, are amortized to
operating expense over the period allowed for rate-making purposes. It
also includes nonrefundable contributions in aid of construction, which
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, 2001 are as follows:
Annual Depreciation Rate Ranges
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
Chugach uses average service life rates set forth in the most recently
approved depreciation study. 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 weighted average rate
(adjusted monthly) of 7.5% during 2001, 7.9% during 2000 and 7.4% during
1999.
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 average cost or market.
Fair Value of Financial Instruments
SFAS 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).
Treasury 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 re-financings. The Association
accounted for the agreements under SFAS 80 and 71 through December 31,
2000, and SFAS 133, 138 and 71 subsequent to that date. The Association
adopted SFAS 133 on January 1, 2001. 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, 2001, 2000 and 1999 the
Association received no unrelated business income.
Environmental Remediation Costs
The Association accrues for losses and establishes a liability 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. However, various remediation costs may be recoverable
through rates and accounted for as a regulatory asset.
2) Utility Plant Summary
Major classes of electric plant as of December 31 are as follows:
2001 2000
---- ----
Electric plant in service:
Steam production plant $60,392,869 $60,392,869
Hydraulic production plant 8,125,226 8,798,695
Other production plant 94,207,814 106,017,802
Transmission plant 206,972,504 211,860,829
Distribution plant 177,457,788 170,378,081
General plant 46,757,035 45,835,618
Unclassified electric plant in service* 111,809,111 77,054,390
Equipment under capital lease 56,323 56,323
Other 8,539,193 6,732,523
--------- ---------
Total electric plant in service 714,317,863 687,127,130
Construction work in progress 28,887,008 42,027,617
---------- ----------
Total electric plant in service and
construction work in progress $743,204,871 $729,154,747
============ ============
<FN>
*Unclassified electric plant in service consists of complete unclassified of general plant, generation, transmission and
distribution projects
</FN>
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:
2001 2000
---- ----
National Rural Utilities Cooperative Finance
Corporation (NRUCFC) $6,095,980 $6,095,980
National Bank for Cooperatives (CoBank) 4,216,115 3,600,133
NRUCFC capital term certificates 45,616 33,733
Other 127,475 127,307
------- -------
$10,485,186 $9,857,153
=========== ==========
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 capital credit retirement program, which
is contained in the Chugach business plan. This establishes, in general,
a plan to return the capital credits of wholesale and retail customers
based on the members' proportionate contribution to Association
assignable margins on an approximately 15-year rotation. At December 31,
2001, out of the total of $125,184,374 patronage capital, the Association
had assigned $122,055,164 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 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.
In November 2001, the Board of Directors authorized the retirement of
$3,000,000 of retail patronage for 1985.
Following is a five-year summary of anticipated capital credit
retirements:
Year ending Wholesale Retail Total
2002 $0 $3,500,0 $3,500,000
2003 0 3,500,0 3,500,000
2004 1,359,000 2,141,0 3,500,000
2005 1,109,000 2,391,0 3,500,000
2006 1,671,000 1,829,0 3,500,000
(5) Other Equities
A summary of other equities at December 31 follows:
2001 2000
---- ----
Nonoperating margins, prior to 1967 $23,625 $23,625
Donated capital 183,907 183,907
Unredeemed capital credit retirement 5,357,702 4,672,892
--------- ---------
$5,565,234 $4,880,424
(6) Debt
Long-term obligations at December 31 are as follows: 2001 2000
---- ----
2001 Series A Bond of 6.55% maturing in 2011 with interest payable
semi-annually March 15 and September 15: $150,000,000 $0
First mortgage (1991 Series A) Bond of 8.08% maturing in 2002 and 9.14%
maturing in 2022 with interest payable semi-annually March 15 and
September 15:
8.08% 5,232,000 11,329,000
9.14% (refinanced in 2002 by the 2002 Series A and Series B Bond 149,310,000 164,310,000
maturing in 2012, see note 18)
CoBank 8.95% bond maturing in 2002, with interest payable monthly and
principal due semi-annually 177,945 511,295
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 interest payable monthly (refinanced in 2001
by the 2001 Series A Bond maturing in 2011, see note below) 0 42,500,000
CoBank, variable interest, with a rate of 8.20% at December 31, 2000, bonds
maturing in 2002, with interest payable monthly (refinanced in 2001
by the 2001 Series A Bond maturing in 2011, see note below) 0 30,000,000
- ----------
Total long-term obligations 374,719,945 318,650,295
Less current installments 10,409,945 6,430,350
---------- ---------
Long-term obligations, excluding current installments $364,310,000 $312,219,945
============ ============
Covenants
Chugach is in compliance with all covenants set forth in the Indenture of
Trust, dated September 15, 1991.
Security
Substantially all assets are pledged as collateral for the long-term
obligations until retirement of the 1991 Series A Bond and subsequent
institution of the Amended and Restated Indenture. On the release date,
the Bonds will become general unsecured and unsubordinated obligations.
Under the Amended Indenture, Chugach is prohibited from creating or
permitting to exist any mortgage, lien, pledge, security interest or
encumbrance on our properties and assets (other than those arising by
operation of law) to secure the repayment of borrowed money or the
obligation to pay the deferred purchase price of property unless we
equally and ratably secure all bonds subject to the Amended Indenture,
except that we may incur secured indebtedness in an amount not to exceed
$5 million or enter into sale and leaseback or similar agreements.
Rate
The Indenture requires Chugach, subject to any necessary regulatory
approval; to establish and collect rates reasonably expected to yield
margins for interest equal to at least 1.20 times total interest expense.
Margins for interest generally consist of our assignable margins plus
total interest expense and income tax accruals. The Amended Indenture
will require Chugach, subject to any necessary regulatory approval; to
establish and collect rates reasonably expected to yield margins for
interest equal to at least 1.10 times total interest expense.
Distribution to Members
The Indenture prohibits Chugach from making any distribution of patronage
capital to our customers if an event of default under the Indenture then
exists. Otherwise we are permitted to make distributions to our members
after December 31, 1990 in the aggregate amount of $7 million plus 35% of
the aggregate assignable margins earned after December 31, 1990. This
restriction does not apply if, after the distribution, our aggregate
equities and margins as of the end of the immediately preceding fiscal
quarter would be equal to at least 45% of our total liabilities and
equities and margins. The Amended Indenture will prohibit Chugach from
making any distribution of patronage capital to our customers if an event
of default under the Amended Indenture then exists.
Otherwise, we may make distributions to our members in each year equal to
the lesser of 5% of our patronage capital or 50% of assignable margins
for the prior fiscal year. This restriction will not apply if, after the
distribution, our aggregate equities and margins as of the end of the
immediately preceding fiscal quarter would be equal to at least 30% of
our total liabilities and equities and margins. The Association does not
anticipate that this provision will limit the anticipated capital credit
retirements described in note 4.
Maturities of Long-term Obligations
Long-term obligations at December 31, 2001, mature as follows:
Year ending Sinking Fund Sinking Fund Principal maturities Total
December 31 Requirements Requirements
2001 Series A First mortgage CoBank
Bonds Bonds Mortgage bonds
2002 $0 $5,232,000 $5,177,945 $10,409,945
2003 0 0 865,821 865,821
2004 0 0 945,000 945,000
2005 0 0 11,031,393 11,031,393
2006 0 0 1,125,687 1,125,687
Thereafter 150,000,000 149,310,000 51,032,099 350,342,099
----------- ----------- ---------- -----------
$150,000,000 $154,542,000 $70,177,945 $374,719,945
============= ============= =========== ============
<FN>
All the sinking fund requirements for the 1991 Series A Bond due 2022,
have been reflected as thereafter due to the refinancing in February 2002
discussed below.
</FN>
The Association had an annual line of credit of $35,000,000 in 2001 and
2000 available with CoBank. The CoBank line of credit expires August 1,
2002, but carries an annual automatic renewal clause. At December 31,
2001, there was $11 million outstanding on this line of credit, which
carried an interest rate of 3.75%. At December 31, 2000, there was $35
million outstanding on this line of credit, which carried an interest
rate of 8.20%. In addition, the Association had an annual line of credit
of $50,000,000 available at December 31, 2001 and 2000 with NRUCFC. At
December 31, 2001, there was no outstanding balance on this line of
credit. At December 31, 2000, there was $5 million outstanding on this
line of credit, which carried an interest rate of 8.55%. The NRUCFC line
of credit expires October 14, 2002.
Refinancing
On April 17, 2001, Chugach issued $150,000,000 of 2001 Series A Bond, for
the purpose of retiring indebtedness outstanding under existing lines of
credit and outstanding bonds, for capital expenditures and for general
working capital. The lines of credit had an aggregate outstanding
principal balance of $55,000,000, as of April 17, 2001, were renewable
annually and bore interest at variable annual rates ranging from 7.55% to
7.80% at April 17, 2001. The variable-rate bonds retired had an aggregate
outstanding principal balance of $72,500,000, as of April 17, 2001, would
have matured in 2002 and bore interest at a variable rate that was 7.55%
on April 17, 2001.
The 2001 Series A Bond will mature on March 15, 2011, and bear interest
at 6.55% per annum. Interest will be paid semi-annually on March 15 and
September 15 of each year commencing on September 15, 2001. The 2001
Series A Bond is secured by a first lien on substantially all of
Chugach's assets. The first lien will be automatically released when all
bonds issued by Chugach prior to April 1, 2001, cease to be outstanding
or their holders consent to conversion to unsecured status. Thereafter,
the 2001 Series A Bond will be unsecured obligations, ranking equally
with Chugach's other unsecured and unsubordinated obligations.
On September 19, 1991, Chugach issued $314,000,000 of First Mortgage
Bond, 1991 Series A (Bond), 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 bond maturing in 2002 (1991 Series A 2002 Bond) is subject to annual
sinking fund redemption at 100% of the principal amount thereof, which
commenced March 15, 1993. The bond maturing in 2022 (1991 Series A 2022
Bond) is subject to annual sinking fund redemption at 100% of the
principal amount thereof commencing March 15, 2003. The Series A 2002
Bond is not subject to optional redemption. The Series A 2022 Bond is
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 Bond is
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 February 1999, Chugach reacquired $11,000,000 of the 1991 Series A
2022 Bond at a premium of 117.05. Total transaction costs, including
accrued interest and premium, were $13,322,344.
In February 1999, Chugach reacquired $14,000,000 of the 1991 Series A
2022 Bond at a premium of 116.25. Total transaction costs, including
accrued interest and premium, were $16,868,592.
In February 1999, Chugach reacquired $9,895,000 of the 1991 Series A 2022
Bond at a premium of 116.75. Total transaction costs, including accrued
interest and premium, were $11,974,467.
In March 2000, Chugach reacquired $8,500,000 of the 1991 Series A 2022
Bond at a premium of 104.00. Total transaction cost, including accrued
interest and premium, were $9,215,502.
In April 2000, Chugach reacquired $10,000,000 of the 1991 Series A 2022
Bond at a premium of 108.875. Total transaction costs, including accrued
interest and premium, were $10,953,511.
In May 2001, Chugach reacquired $10,000,000 of its 1991 Series A 2022
Bond at a premium of 111.00. Total transaction costs, including accrued
interest and premium, were $11,242,178.
In December 2001, Chugach reacquired $5,000,000 of its 1991 Series A 2022
Bond at a premium of 111.00. Total transaction costs, including accrued
interest and premium, were $5,661,711.
The premiums paid are reflected as a regulatory asset and amortized over
the life of the 2001 Series A Bond.
Treasury Rate Lock Agreements
On March 17, 1999, Chugach entered into a U.S.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 Bond due
2022 on their optional call date (March 15, 2002). On May 11, 2001,
Chugach terminated the $18.7 million 30-year U.S. Treasury portion of the
Treasury Rate Lock Agreement in receipt of payment of $10,000 by Lehman.
On December 7, 2001, Chugach terminated 50%, or $98.0 million, of the
10-year U.S. Treasury portion of the U.S. Treasury Rate Lock Agreement
for a settlement payment of $4 million to Lehman Brothers. Chugach
settled the remaining 50% of the 10-year U.S. Treasury portion of the
Treasury Rate Lock Agreement for $3 million on December 19, 2001. The
settlement payments were accounted for as regulatory assets. Chugach
believes the regulatory assets will be recovered through rates, however,
if the RCA does not approve this treatment, such amounts that are not
deferrable under SFAS 133 would be charged off. As of December 31, 2001,
the aggregate principal amount of the Series A Bond due 2022 was
$149,310,000.
(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:
2001 2000
---- ----
Carrying Fair Carrying Fair
Value Value Value Value
Long-term obligations
(including current installments) $374,720 $390,320 $318,650 $335,155
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 $1,990,000 in 2001, $2,017,000 in 2000 and
$1,832,000 in 1999. In 2001, 2000 and 1999, the Association contributed
$1,397,000, $1,057,000 and $868,000, respectively, to the NRECA plan.
(9) Deferred Charges
Deferred charges consisted of the following at December 31:
2001 2000
---- ----
Debt issuance and reacquisition costs $15,649,174 $5,399,282
Refurbishment of transmission equipment 243,828 253,087
Computer software and conversion 8,161,890 10,672,135
Studies 1,776,576 1,724,936
Business venture studies 531,416 562,435
Fuel supply negotiations 348,986 346,894
Major overhaul of steam generating unit 17,092 222,198
Environmental matters and other 272,899 261,892
Other regulatory deferred charges 1,704,432 0
--------- -
$28,706,293 $19,442,859
=========== ===========
(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) Deferred Credits
Deferred credits at December 31 consisted of the following:
2001 2000
---- ----
Regulatory liability - unamortized gain on
reacquired debt $15,629,104 $18,066,673
Refundable consumer advances for construction 2,163,944 1,771,302
Estimated initial installation costs for transformers and meters 447,378 323,821
Post retirement benefit obligation 405,700 286,200
New business venture 30,256 20,254
Other 771,409 957,089
------- -------
$19,447,791 $21,425,339
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 pass 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 $1,231,000 of
the deferred gain was amortized in 2001. Approximately $1,553,000 of the
deferred gain was amortized in 2000. Approximately $1,215,000 of the
deferred gain was amortized in 1999.
(12) 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, 2001 (the most recent date for which information is available). The
Association's share of expenses was $3,929,614 in 2001, $3,696,829 in
2000 and $3,902,737 in 1999 and is included in purchased power in the
accompanying financial statements.
(In thousands) Total Proportionate Share
----- -------------------
Plant in service $ 306,872 $ 93,289
Accumulated depreciation (67,534) (20,530)
Interest expense 9,467 2,878
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).
(13) 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 $1,957,742 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 operation, maintenance and capital
improvement costs to the plant, as well as to the transmission line
between Anchorage and the plant. Under net billing arrangements, Chugach
then reimburses MEA for their share of the costs.
(14) 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 at
the end of the currently committed volumes or the contract expiration
dates of 2015 and 2025.
Significant Customers
The Association is the principal supplier of power under long-term
wholesale power contracts with MEA and HEA. These contracts represented
$57.7 million or 32.3% of operating revenues in 2001, $45.2 million or
28.5% in 2000 and $43.4 million or 30.4% in 1999. These contracts 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. A Federal Energy Regulatory Commission
(FERC) approved plan, prepared in consultation with the Environmental
Protection Agency (EPA), was implemented to remediate the PCBs in the
plant. As a condition of its approval of the license amendment for the
overhaul project, FERC required Chugach to also investigate the presence
of PCBs in Kenai Lake. A sampling plan was developed by Chugach in
consultation with various agencies and approved by FERC. In 2000, Chugach
sampled sediments and fish collected from Kenai Lake and other waters.
While extremely low levels of PCBs were found in some sediment samples
taken near the plant, no pathway from sediment to fish was established.
Additional sediment sampling and analysis in this area is being
performed. While the presence of PCBs in fish did not reveal amounts
above background levels, Chugach has conducted additional sampling and
analysis of fish in Kenai Lake and other waters and is preparing a report
to FERC, analyzing the results of the sampling. Management believes the
costs of this work will be recoverable through rates and therefore will
have no material impact on our financial condition or results of
operations. The RCA has issued an order to Chugach generally allowing
prudently incurred remediation costs at Cooper Lake to be recovered
through rates, however, the RCA has not approved the final recovery
amount in this matter and will review these costs as part of the 2000
test year rate case.
Legal Proceedings
Matanuska Electric Association, Inc. v. Chugach Electric Association,
Inc. Superior Court Case No. 3AN-99-8152 Civil
-------------------------------------------------------------------------
This action was a claim for a breach of the Tripartite Agreement, which
is the contract governing the parties' relationship for a 25-year period
from 1989 through 2014 and governing the Company's sale of power to MEA
during that time. MEA asserted the Company breached that contract by
failing to provide a variety of kinds of information, by failing to
properly manage the Company's long-term debt, and by failing to bring its
base rate action to the Joint Rates Committee before presentation to the
RCA. All of MEA's claims have been dismissed. MEA has indicated that it
intends to appeal to the Alaska Supreme Court, at a minimum, the Superior
Court's dismissal of its financial mismanagement claim.
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 $.000360,
effective October 1, 2001.
(15) Recent Accounting Pronouncements
Chugach was required to adopt SFAS 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS 138, Accounting
for Certain Derivative Instruments and Certain Hedging Activities, an
Amendment of FASB Statement No. 133, effective January 1, 2001. This new
standard requires all derivative financial instruments to be reflected on
the balance sheet. The adoption resulted in Chugach establishing a
liability for the settlement of U.S. Treasury Rate Lock Agreements.
In July 2001, the Financial Accounting Standards Board issued Statement
141, Business Combinations, and Statement 142, Goodwill and Other
Intangible Assets. Statement 141 requires that the purchase method of
accounting be used for all business combinations initiated or completed
after June 30, 2001. Statement 142 will require that goodwill and
intangible assets with indefinite useful lives no longer be amortized,
but instead tested for impairment at least annually. The provisions of
Statement 142 are required to be applied starting with fiscal years
beginning after December 15, 2001. Management believes the adoption of
Statement 141 and 142 will have no impact on our financial statements.
In August 2001, the Financial Accounting Standards Board issued Statement
143, Accounting for Asset Retirement Obligations. Statement 143 requires
an enterprise to record the fair value of an asset retirement obligation
as a liability in the period in which it incurs a legal obligation
associated with the retirement of tangible long-lived assets and an
increase to the carrying amount of the related long-lived asset, which is
depreciated over the life of the asset. Enterprises are required to adopt
Statement 143 for fiscal years beginning after June 15, 2002. Management
believes the adoption of Statement 143 will have no impact on our
financial statements.
In October 2001, the Financial Accounting Standards Board issued
Statement 144, Accounting for the Impairment or Disposal of Long-Lived
Assets. Statement 144 addresses financial accounting and reporting for
the impairment or disposal of long-lived assets. While Statement 144
supersedes FASB Statement 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, it retains
many of the fundamental provisions of that Statement, and broadens the
presentation of discontinued operations to include more disposal
transactions. Statement 144 also supersedes the accounting and reporting
provisions of Accounting Principles Board (APB) Opinion 30, Reporting the
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events
and Transactions, for the disposal of a segment of a business. However,
it retains the requirement in Opinion 30 to report separately
discontinued operations and extends that reporting to a component of an
entity that either has been disposed of or is classified as held for
sale. Statement 144 is effective for fiscal years beginning after
December 15, 2001, and interim periods within those fiscal years.
Management believes the adoption of Statement 144 will have no impact on
our financial statements.
(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 following is a tabulation of business segment information
for the years ended December 31:
2001 2000 1999
---- ---- ----
Operating Revenues
Internet $196,051 $1,170,448 $374,296
Energy 178,399,163 157,370,666 142,270,031
----------- ----------- -----------
Total operating revenues 178,595,214 158,541,114 142,644,327
=========== =========== ===========
Assignable Margins
Internet (165,273) (1,505,518) (1,293,388)
Energy 5,704,409 11,185,296 10,960,822
--------- ---------- ----------
Total assignable margins 5,539,136 9,679,778 9,667,434
========= ========= =========
Assets
Internet 0 550,275 564,477
Energy 572,178,712 539,195,705 517,791,060
----------- ----------- -----------
Total assets 572,178,712 539,745,980 518,355,537
=========== =========== ===========
Capital Expenditures
Internet 0 163,565 508,082
Energy 36,408,253 46,566,478 41,376,641
---------- ---------- ----------
Total capital expenditures 36,408,253 46,730,043 41,884,723
========== ========== ==========
As of March 6, 2001, with an effective date of March 20, 2001, Chugach
sold the bulk of it's internet service provider assets related to dial-up
services (excluding DSL services) to GCI Communication Corporation. The
aggregate purchase price was $759,049 at closing, plus an additional
amount of $70,075, which was based on number of subscriber accounts
retained during the ninety-day transition period following closing. These
transactions resulted in a loss of $258,073.
(17) Quarterly Results of Operations (unaudited)
2001 Quarter Ended
Dec. 31 Sept. 30 June 30 March 31
------- -------- ------- --------
Operating Revenue $52,194,258 $42,186,684 $39,018,695 $45,195,577
Operating Expense 43,744,371 35,591,202 32,788,603 35,372,545
Net Interest 6,820,907 6,680,125 7,037,810 6,690,671
--------- --------- --------- ---------
Net Operating Margins 1,628,979 (84,643) (807,718) 3,132,361
Non-Operating Margins 931,967 126,903 222,619 388,668
--------- --------- --------- ---------
Assignable Margins $2,560,946 $42,260 ($585,099) $3,521,029
========== ======= ========== ==========
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
========== ======== ========== ==========
(18) Subsequent Events
Refinancing
On February 1, 2002, Chugach issued $120,000,000 of 2002 Series A Bond
and $60,000,000 of 2002 Series B Bond for the purpose of redeeming $149.3
million in principal amount of the 1991 Series A Bond due 2022, to pay
the redemption premium on the 1991 Series A Bond due 2022 in the amount
of $13.6 million and for general working capital. The 2002 Series A Bond
will mature on February 1, 2012, and bear interest at 6.20% per annum.
Interest will be paid semi-annually on February 1 and August 1 of each
year commencing on August 1, 2002. Chugach may not redeem the 2002 Series
A Bond prior to maturity.
The 2002 Series B Bond (the "Auction Rate Bond") will mature on February
1, 2012. The Auction Rate Bond will bear interest from the date of
original delivery to and through February 27, 2002, at a rate established
by the underwriter prior to their date of delivery
and afterwards, will initially bear interest at the rate set for 28-day
auction periods. The initial auction date will be February 27, 2002. The
applicable interest rate for any 28-day auction period will be the term
rate established by the auction agent based on the terms of the auction.
The Auction Rate Bond may be converted, in our discretion, to a daily,
seven-day, 35-day, three-month or a semi-annual period or a flexible
auction period. The Auction Rate Bond is subject to optional and
mandatory redemption and to mandatory tender for purchase prior to
maturity in the manner and at the times described herein. Bankers Trust
Company will act as the auction agent and J.P. Morgan Securities Inc.,
will act as the initial broker-dealer for the Auction Rate Bond.
Payment of the 2002 Series A Bond and the Auction Rate Bond (collectively
the "Bonds") initially will be secured by a first lien on substantially
all of Chugach's tangible and some intangible properties. The first lien
will be automatically released when all bonds issued by Chugach prior to
April 1, 2001, cease to be outstanding or their holders consent to the
release of the lien. After that time, the Bonds will be unsecured
obligations, ranking equally with our other unsecured and unsubordinated
obligations. In addition, we will be limited in our ability to secure
obligations for borrowed money or the deferred purchase price of property
after that time unless Chugach equally and ratably secures our
outstanding indebtedness subject to the Indenture governing the Bonds.
Treasury Rate Lock Agreements
On January 14, 2002, Chugach entered into an 18-day rate lock agreement
with JP Morgan on the $120 million 10-year term bond of the proposed 2002
financing based on the 10-year treasury issued August 15, 2001, that was
trading at 4.877%. That rate, along with a 0.041% U.S. note fee, set a
benchmark rate for the transaction at 4.918%. Chugach terminated the rate
lock on February 1, 2002, which generated a payment to Chugach of $1.2
million. The settlement payment will be reflected as an offset to
regulatory assets.
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......................... 63 General Manager
Lee D. Thibert.............................. 46 Executive Manager, Transmission and
Distribution Network Services
Evan J. Griffith............................ 60 Executive Manager, Finance and Energy Supply
William R. Stewart.......................... 54 Executive Manager, Retail Services
Bruce Davison............................... 53 President and Director
H.A. ("Red") Boucher........................ 81 Vice President and Director
Christopher Birch........................... 51 Secretary and Director
Jeffrey W. Lipscomb......................... 51 Treasurer and Director
Elizabeth ("Pat") Kennedy................... 63 Director
Pat Jasper.................................. 72 Director
Dave Cottrell............................... 54 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. Mr. Bjornstad has given notice
of his intention to retire in May 2002. The Board of Directors has undertaken
the process of finding a replacement.
Lee D. Thibert was appointed our Executive Manager, Transmission &
Distribution Network Services in a reorganization on June 1, 1997. 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
Bruce Davison serves as President of the Board. He had 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 our Bylaws Committee. He is a partner in the law firm of Davison & Davison,
Inc.
Red Boucher became Vice President of the Board in April 2001. He 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.
Chris Birch has been serving as Secretary of the Board since April
2001. He 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.
Jeff Lipscomb was elected director in April 2000 and currently serves
as Treasurer. Mr. Lipscomb is the principal of JWL Engineering, which he founded
in 1995. He is a professional mechanical engineer with over 20 years of
experience in Alaskan oil and gas production facility design.
Pat Kennedy has served on the board since 1993 and has served as both
Secretary and President. She is an attorney who has been licensed to practice
law since 1976.
Pat Jasper most recently served as the President of the Board from
April 2000 to April 2001. 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.
Dave Cottrell was elected to the Board in April 2001. Mr. Cottrell has
been the president and managing partner at Mikunda Cottrell & Co., an accounting
firm he owns in Anchorage, since 1977. Mr. Cottrell is a certified public
accountant.
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 2001, and for all such
executive officers as a group:
Name Principal Position Year Salary Bonus Total
Eugene N. Bjornstad General Manager 2001 $211,077 $15,000 $226,077
2000 230,074 - 230,074
1999 168,057 36,891 204,948
Lee D. Thibert Executive Manager, 2001 142,425 - 142,425
Transmission & 2000 131,710 - 131,710
Distribution
Network Services 1999 123,390 $12,757 136,147
Evan J. Griffith Executive Manager, 2001 142,884 7,770 150,654
Finance
& Energy Supply 2000 131,657 - 131,657
1999 135,140 12,757 147,897
William R. Stewart Executive Manager, 2001 158,902 - 158,902
Retail Services 2000 134,398 - 134,398
1999 137,376 12,757 150,133
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 us 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 (defined below)
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, 2001 taken into account under the
Plan for the executive officers is shown below. Base salary for 2001 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 17.0 $170,000
Lee D. Thibert................ Executive Manager, Transmission 13.0 $137,322
& Distribution Network Services
Evan J. Griffith.............. Executive Manager, Finance & 11.0 $136,677
Energy Supply
William R. Stewart............ Executive Manager, Retail 30.0 $136,677
Services
Employment Arrangements
In August 2001, we entered into an employment agreement with Eugene
Bjornstad, our General Manager. He is paid an annual base salary of $175,000.
Mr. Bjornstad also is eligible to receive additional compensation, bonus and
benefits for meeting performance goals established annually by the Board of
Directors. In the event that Mr. Bjornstad is terminated without cause, he will
be entitled to severance in an amount equal to six months of his annual salary,
plus any accrued annual leave and any bonuses or other compensation then due.
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 36
Balance Sheets, December 31, 2001 and 2000 37-38
Statements of Revenues, Expenses and Patronage Capital,
Years ended December 31, 2001, 2000 and 1999 39
Statements of Cash Flows,
Years ended December 31, 2001, 2000 and 1999 40
Notes to Financial Statements 41-65
Financial Statement Schedules
Included in Part IV of this Report:
Schedule II - Valuation and Qualifying Accounts,
Years ended December 31, 2001, 2000 and 1999 73
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, 2001 (441,933) (116,881) 240,057 (318,757)
December 31, 2000 (389,223) (373,666) 320,956 (441,933)
December 31, 1999 (447,908) (331,895) 390,580 (389,223)
EXHIBITS
Listed below are the exhibits, which are filed as part of this Report:
Exhibit Number Description
3.1 Articles of Incorporation of the Registrant. (13)
3.2 Bylaws of the Registrant. (12)
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. (1)
4.8 Seventh Supplemental Indenture of Trust between the Registrant and Seattle-First National Bank dated
June 1, 1997. (2)
4.9 Eighth Supplemental Indenture of Trust between the Registrant and Security Pacific Bank Washington, N.A.
dated February 4, 1998. (4)
4.10 Ninth Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association
dated April 25, 2000. (9)
4.11 Tenth Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association
dated April 1, 2001. (11)
4.12 Form of Eleventh Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National
Association. (14)
4.13 Amended and Restated Indenture between the Registrant and U.S. Bank Trust National Association dated
April 1, 2001. (11)
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. (1)
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. (8)
10.4.1 Amendment No. 1 to Agreement for the Sale and Purchase of Electric Power and Energy between the
Registrant and the City of Seward dated effective as of July 9, 2001. (13)
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. (1)
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. (11)
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. (1)
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. (11)
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. (8)
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. (1)
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.
(11)
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. (8)
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. (1)
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. (8)
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. (1)
10.18 Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. (11)
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. (1)
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. (11)
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. (1)
10.33 Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. (3)
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. (1)
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. (8)
10.39.1 Second Amendment to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between the
Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 1, 2001. (13)
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. (1)
10.44.5 Amendment to Line of Credit Agreement between the Registrant and
CoBank, ACB dated September 30, 2000. (10)
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. (2)
10.47 Fifty Million Dollar Line of Credit Agreement between the Registrant and the National Rural Utilities
Cooperative Finance Corporation dated October 22, 1997. (3)
10.48 International Swap Dealers Association, Inc. Master Agreement between the Registrant and Lehman Brothers
Financial Products Inc. dated March 17, 1999. (6)
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. (7)
10.50 Employment Agreement between the Registrant and Eugene N. Bjornstad dated August 22, 2001. (14)
10.51 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. (5)
12.1 Statement regarding computation of ratios. (14)
(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 (File No.
333-57400) dated March 22, 2001.
(12) Previously filed as an exhibit to the Registrant's Quarterly
Report on Form 10-Q dated March 31, 2001.
(13) Previously filed as an exhibit to the Registrant's Quarterly
Report on Form 10-Q dated June 30, 2001.
(14) Previously filed as an exhibit to the Registrant's Registration Statement on Form S-1 (File No.
333-75840) dated December 21, 2001.
REPORTS ON FORM 8-K
The Company was not required to file any report on Form 8K for the year ended
December 31, 2001.
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 29, 2002.
CHUGACH ELECTRIC ASSOCIATION, INC.
By: /s/ Eugene N. Bjornstad
Eugene N. Bjornstad, General Manager
Date: March 29, 2002
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 29, 2002:
/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/ Bruce Davison
Bruce Davison President
(Principal Executive Officer & Director)
/s/ H.A. Boucher
H.A. Boucher Director & Vice President
/s/ Christopher Birch
Christopher Birch Director & Secretary
/s/ Jeffrey Lipscomb
Jeffrey Lipscomb Director & Treasurer
/s/ Elizabeth Page Kennedy
Elizabeth Page Kennedy Director
/s/ Patricia B. Jasper
Patricia B. Jasper Director
/s/ Dave Cottrell
Dave Cottrell 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 2001 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.