UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2002
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or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from _________________________to______________________
Commission file number 33-42125
Chugach Electric Association, Inc.
(Exact name of registrant as specified in its charter)
Alaska 92-0014224
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5601 Minnesota Dr., Anchorage, Alaska 99518
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (907) 563-7494
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
- ----------------------------------- ----------------------------------------
- ----------------------------------- ----------------------------------------
Securities registered pursuant to Section 12(g) of the Act:
- --------------------------------------------------------------------------------
(Title of class)
- --------------------------------------------------------------------------------
(Title of class)
Indicate by check mark whether registrant (1) has filed 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 Registration S-K (Section 229.405 of this chapter) 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
Indicate by check mark whether the registrant is an accelerated filer(as defined
in Rule 12b-2 of the Act) __Yes X No
State the aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the price at which the common equity
was last sold, or the average bid and asked price of such common equity, as of
the last business day of the registrant's most recently completed second fiscal
quarter. N/A
CHUGACH ELECTRIC ASSOCIATION, INC.
2002 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 35
Item 8 - Financial Statements and Supplementary Data 37
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 69
PART III
Item 10 - Directors and Executive Officers of the Registrant 69
Item 11 - Executive Compensation 72
Item 12 - Security Ownership of Certain Beneficial Owners and
Management 75
Item 13 - Certain Relationships and Related Transactions 75
Item 14 - Disclosure Controls and Procedures 75
PART IV
Item 15 - Exhibits, Financial Statement Schedules and Reports on
Form 8-K 76
SIGNATURES 88
Certification of Principal Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002 90
Certification of Principal Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002 91
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) 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 makes its current and periodic reports available, free of
charge, on our website at www.chugachelectric.com as soon as practicable after
filing with the Securities and Exchange Commission (SEC). Our website provides a
link to the SEC website.
Chugach Electric Association, Inc., is the largest electric utility in
Alaska. We are engaged in the generation, transmission and distribution of
electricity to approximately 71,800 metered locations in the Anchorage and upper
Kenai Peninsula areas. Through an interconnected regional electrical system, our
energy is distributed throughout Alaska's Railbelt, a 400-mile-long area
stretching from the coastline of the southern Kenai Peninsula to the interior of
the state, including Alaska's largest cities, Anchorage and Fairbanks. Neither
Chugach 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 Generation and Transmission Power Plant (IGT),
Cooper Lake Hydroelectric Plant and Eklutna Hydroelectric Project, in which we
own a 30% interest. Approximately 85% (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 2002, approximately 84% of our energy was generated at the Beluga
facility. We purchase up to 27.4 megawatts for our retail customers and up to
38.6 megawatts for our wholesale customers from the Bradley Lake Hydroelectric
Project. We also purchase approximately 40 megawatts from the Nikiski power
plant on the Kenai Peninsula. We operate 1,624 miles of distribution line and
402 miles of transmission line. For the year ended December 31, 2002, we sold
2.4 billion kilowatt hours (kWh) of electrical power.
Chugach was organized as an Alaska electric cooperative in 1948.
Cooperatives are business organizations that are owned by their members. As
not-for-profit organizations (Internal Revenue Code 501 (c)(12), 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 for
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, 2002, we had 61,009 retail members receiving service at
approximately 71,800 metered locations and three major wholesale customers. No
individual retail customer receives more than 5% of our power.
Our 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 on the basis of historic cost of service) 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.
Chugach is 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 $.000318 per kWh of retail electricity sold. This charge is assessed to fund
the operations of the RCA. It is a pass-through and thus does not impact our
margins.
Our workforce consists of approximately 350 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, 2006. We also have
an agreement with Hotel Employees, Restaurant Employees (HERE), Local 878 in
effect through June 30, 2006. We believe our relationship with our employees is
good.
Gene Bjornstad, Chugach's former General Manager, gave notice of his
intention to retire in May 2002. On April 25, 2002, the Board of Directors named
Evan J. Griffith as Chugach's new General Manager effective May 6, 2002.
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 do not expect the Alaska legislature to pass a law creating retail
competition for electric service in the foreseeable future. We are not actively
promoting retail competition.
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 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 changes in our base rates by
filing general rate cases with the RCA. While the formal ratemaking process
previously took nine months to one year, on August 10, 2002, A.S. 42.05.175
imposed timelines for RCA decisions. Among other provisions, it provided that
for all dockets commenced on or after July 1, 2002, the RCA shall issue a final
order not later than 15 months after a complete tariff filing is made for a
tariff filing that changes the utility's revenue requirement or rate design. 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. The rate covenants contained in the instruments that
govern our outstanding long-term indebtedness do not impose any greater TIER
requirement than those previously approved 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 Amended and Restated Indenture, which became effective January 22,
2003, governs all of our outstanding bonds and requires us to set rates expected
to yield margins for interest equal to at least 1.10 times total interest
expense. The CoBank Master Loan Agreement also requires Chugach to establish and
collect rates reasonably expected to yield margins for interest equal to at
least 1.10 times interest expense. On February 6, 2003, we received Order
U-01-108(26) from the RCA, based on our general rate case on the 2000 test year,
that revised our overall TIER downward from 1.35 to 1.30. Based on all the
adjustments stated in Order U-01-108(26), see "Management's Discussion and
Analysis - Results of Operations - Overview - Rate Regulation and Rates," for
the year ended December 31, 2002, our achieved TIER was calculated to be 0.92.
In our general rate case, we proposed that margins be calculated using
a rate base/rate of return methodology rather than the TIER methodology
previously used. Under Order U-01-108(26), we will be required to use TIER in
calculating return levels.
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, 2002:
Percent of Total
MWh 2002 Revenues 2002 Revenues
--- ------------- ---------------
Direct retail sales:
Residential.................... 534,869 $58,193,464 34%
Commercial..................... 606,237 51,888,550 31%
------- ---------- ---
Total.......................... 1,141,106 110,082,014 65%
Wholesale sales:
MEA............................ 584,726 30,018,227 18%
HEA............................ 482,619 22,035,973 13%
Seward......................... 59,521 2,709,752 1%
------ --------- --
Total.......................... 1,126,866 54,763,952 32%
Economy energy sales(1) ............ 125,784 4,567,179 3%
------- ---------
Total sales to customers............ 2,393,756 169,413,145 100%
========= ====
Miscellaneous energy revenue 2,531,773
---------
Total energy revenues $171,944,918
============
(1) Economy sales were made to GVEA and AML&P.
Retail Customers
Service Territory
Our retail service area covers the populated areas of Anchorage (other
than downtown Anchorage) as well as remote mountain areas and villages. The
service area ranges from the northern Kenai Peninsula on the south, to Tyonek on
the west, to Whittier on the east and to Fort Richardson on the north.
Customers
As of December 31, 2002, we had 61,009 members being served by
approximately 71,800 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 2002, our wholesale power contracts,
including the fuel component, produced $54.8 million in revenues, representing
32% 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 the firm, all requirement sales
to MEA and one for firm, partial requirement sales to HEA. AEG&T is a generation
and transmission cooperative that was formed by MEA and HEA in the mid 1980's.
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 now 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. Although management cannot predict the outcome, we
do not expect a decline in revenue as a result of this transfer.
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 11, 2001, but we negotiated an
amendment to the agreement that extended its term to January 31, 2006. The RCA
conditionally approved the extension on July 9, 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 a contractual priority right under our agreement
with GVEA. Under this provision, if GVEA requires non-firm energy in sufficient
quantities, we have an opportunity to sell two-thirds of the first 450,000 MWh
and an additional 80% of the excess over 450,000 MWh of the non-firm energy that
GVEA purchases each year if we are capable of producing that energy. Under the
above provisions, non-firm sales to GVEA for the years 2002, 2001 and 2000 have
been 125,462 MWh, 81,924 MWh and 267,855 MWh, respectively. No seller enjoys a
contractual priority in making such sales. GVEA makes purchases from the seller
offering the lowest competitive price. The other seller, AML&P, is expected to
dominate sales in the Economy Energy Spot Market for the immediate future.
Load Forecasts
The following table sets forth our projected load forecasts for the
next five years:
Load (MWh) 2003 2004 2005 2006 2007
---------- ---- ---- ---- ---- ----
Retail............ 1,154,000 1,173,000 1,191,000 1,201,000 1,214,000
Wholesale......... 1,181,000 1,215,000 1,245,000 1,262,000 1,286,000
Economy........... 219,000 165,000 165,000 165,000 165,000
Losses............ 140,000 143,000 146,000 147,000 149,000
--------- --------- --------- --------- ---------
Total...... 2,694,000 2,696,000 2,747,000 2,775,000 2,814,000
========= ========= ========= ========= =========
Sales are expected to increase over the next five years principally due
to economic growth in the service sector. Our total energy requirements are
expected to grow at an average compounded annual rate of 1.7% from 2003 to 2007,
retail sales at a rate of 1.3% and wholesale sales at a rate of 2.2%. These
projections are based on assumptions that management believes to be reasonable.
If one or more of these assumptions proves inaccurate in light of actual events,
our actual load requirements for one or more of the years could vary materially
from the forecast.
Item 2 - Properties
General
We have 527 megawatts of installed capacity consisting of 17 generating
units at five power plants. These include 380.9 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 19.2 megawatts at the Cooper Lake
facility, which is also on the Kenai Peninsula. We also have 11.7 megawatts of
capacity from the two Eklutna Hydroelectric 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 IGT 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 380.9 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 received a hot gas path inspection in 2002. Beluga
unit 6 was "repowered" in 2000 adding in excess of 20 years to its life. Beluga
unit 7 was "repowered" in 2001. Beluga unit 8, a steam turbine, was overhauled
in 1994 and received another major overhaul in 2002.
The following matrix depicts nomenclature, run hours for 2002 and
percentages of contribution and other historical information for all Chugach
generation units.
Percent of
total Percent of
Commercial Operation Rating Run hours generation time
Facility Date Nomenclature (MW)(1) (2002) hours available
-------- ---- ------------ ------- ------ ----- ---------
Beluga Power
Plant (3)
1 1968 GE Frame 5 19.6 672.8 1.44 89.52
2 1968 GE Frame 5 19.6 556.9 1.20 93.49
3 1972 GE Frame 7 64.8 4077.8 8.75 79.09
5 1975 GE Frame 7 68.7 5224.6 11.22 93.01
6 1975 BB 11D-4NM 75.1 8311.4 17.84 95.41
7 1978 BB 11D-4NM 80.1 7382.2 15.85 84.27
8 1981 BB DK-21150(2) 53.0 6111.8 13.12 69.77
Bernice Lake
Power Plant
2 1971 GE Frame 5 19.0 0.0 0.00 100
3 1978 GE Frame 5 26.0 651.2 1.40 97.05
4 1981 GE Frame 5 22.5 615.1 1.32 72.81
Cooper Lake
Hydroelectric
Plant
1 1960 BB MV 230/10 9.6 6304.2 13.53 94.83
2 1960 BB MV 230/10 9.6 6229.1 13.37 94.50
IGT Power Plant
1 1964 GE Frame 5 14.1 181.1 .39 90.01
2 1965 GE Frame 5 14.1 246.2 .53 97.81
3 1969 Westinghouse 191G 18.5 17.6 .04 99.18
Eklutna
Hydroelectric
Plant (4)
1 1955 Newport News 5.8 N/A(5) N/A(5) N/A(5)
2 1955 Oerlikon custom 5.9 N/A(5) N/A(5) N/A(5)
System Total 46582.0 100.00
(1) Capacity rating in MW at 30 degrees Fahrenheit.
(2) Steam-turbine powered generator with heat provided by exhaust from
natural-gas fueled Units 6 and 7 (combined-cycle).
(3) Beluga Unit 4 and Bernice Lake Unit 1 were retired during 1994.
(4) The Eklutna Hydroelectric Plant is jointly owned by Chugach, MEA and AML&P.
The capacity shown is our 30% share of the plant's maximum output.
(5) Because Eklutna Hydroelectric Plant is operated by MEA and managed by a
committee of the three owners, we do not record run hours or in-commission
rates.
Note: GE = General Electric, BB = Brown Boveri
Transmission and Distribution Assets
As of December 31, 2002, our transmission and distribution assets
included 39 substations and 402 miles of transmission lines, 930 miles of
overhead distribution lines and 695 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
Under the Amended and Restated Indenture, all of Chugach's bonds are
general unsecured and unsubordinated obligations. 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 and Restated 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.
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 by additional minor title 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 Property
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, 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
$44 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 2002, 85% of our power was generated from gas, and 84% of that
gas-fired generation took place at Beluga.
Our primary sources of natural gas are the Beluga River Field producers
(ConocoPhillips Alaska, Inc., AML&P and Chevron USA Inc. (Chevron), and
Marathon. ConocoPhillips, AML&P and Chevron each own one-third of the gas
produced from the Beluga River Field and in 2002 provided approximately equal
shares of the Beluga gas. We have approximately 333 billion cubic feet (BCF) of
remaining gas committed to us from the Beluga River Field producers and
Marathon. We currently use approximately 22 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 ConocoPhillips,
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 ConocoPhillips and AML&P contracts is approximately
88% of the price of gas under the Marathon contract (described below) ($1.6300
per thousand cubic feet (MCF) on January 1, 2003), 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) ($2.0375 per MCF on January 1,
2003), 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, 2003, exclusive of taxes, was
$1.8523 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 $0.61 per MCF. In
addition, ENSTAR agreed to transport gas on an interruptible basis for
off-system sales at a rate of $0.29 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 IGT 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 IGT.
Environmental Matters
General
Chugach's operations are subject to certain federal, state and
local environmental laws and regulations, which seek to limit 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.
Chugach is 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
Chugach discovered polychlorinated biphenyls (PCBs) in paint, caulk
and grease at the Cooper Lake Hydroelectric plant during initial phases of a
turbine overhaul. A 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 us in consultation
with state and federal agencies and approved by FERC. In 2000, we sampled
sediments and fish collected from Kenai Lake and other waters. While low
levels of PCBs were found in some sediment samples taken near the plant, no
pathway from sediment to fish was established. While the levels of PCBs in
fish from Kenai Lake were similar to levels found in fish from other lakes
within the region, we conducted additional sampling and analysis of fish in
Kenai Lake and other waters and filed our final report dated April 1, 2002,
with FERC, which analyzed the results of the sampling. Based on these
analyses, we concluded that no further PCB sampling and analysis in Kenai
Lake was necessary. In a letter dated June 13, 2002, FERC informed us that
its review of the report supported our conclusions and agreed we were not
required to conduct further PCB sampling and analysis in Kenai Lake. In its
recent order in our general rate case, Order U-01-108(26), the RCA permitted
the costs associated with the overhaul and the PCB remediation to be
recovered through rates. Consequently, management believes the costs of the
PCB remediation and studies will have no material impact on our financial
condition or results of operations. We will be filing a request in 2003 with
the RCA to allow us to record the costs we incurred to investigate the
presence of PCBs in Kenai Lake to be recovered through rates.
Item 3 - Legal Proceedings
Matanuska Electric Association, Inc., v. Chugach Electric Association, Inc.,
Superior Court Case No. 3AN-99-8152 Civil
This action is 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 our sale of power to MEA during
that time. MEA asserted we breached that contract by failing to provide
information, by failing to properly manage our long-term debt, and by
failing to bring our base rate action to a Joint Committee before presenting
it to the RCA. The committee is defined in the power sales contract and
consists of one MEA and two Chugach board members. All of MEA's claims have
been dismissed. On April 29, 2002, MEA appealed the Superior Court's
decisions relating to our financial management and our failure to bring our
base rate action to the joint committee before filing with the RCA to the
Alaska Supreme Court. We cross-appealed the Superior Court's decision not to
dismiss the financial management claim on jurisdictional and res judicata
grounds. Oral argument has been set by the Supreme Court for April 15, 2003.
Management is uncertain as to the outcome but is vigorously defending the
appeal.
Chugach has 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 are likely
to have a material adverse effect on our results of operations, financial
condition or liquidity.
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 2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Plant, net:
In service $450,480,385 $452,964,686 $427,127,258 $398,544,496 $386,235,421
Construction work in
Progress 20,224,302 28,887,008 42,027,617 47,257,296 30,405,736
---------- ---------- ---------- ---------- ----------
Electric plant, net 470,704,687 481,851,694 469,154,875 445,801,792 416,641,157
Other assets 99,510,187 93,429,493 70,591,105 72,553,745 64,450,293
---------- ---------- ---------- ---------- ----------
Total assets $570,214,874 $575,281,187 $539,745,980 $518,355,537 $481,091,450
============ ============ ============ ============ ============
Capitalization:
Long-term debt 389,834,179 364,310,000 312,219,945 337,150,295 305,917,699
Equities and margins 127,477,895 131,808,706 128,815,340 122,524,645 114,023,296
----------- ----------- ----------- ----------- -----------
Total capitalization $517,312,074 $496,118,706 $441,035,285 $459,674,940 $419,940,995
============ ============ ============ ============ ============
Summary Operations Data
Operating revenues $171,944,918 $178,595,214 $158,541,114 $142,644,327 $141,825,373
Operating expenses 149,369,936 147,496,721 126,430,273 110,456,886 110,737,441
Interest expense 26,230,825 28,353,487 26,158,769 25,228,001 26,011,392
Amortization of gain on
Refinancing 188,082 1,123,973 1,440,479 1,092,620 1,542,723
------- --------- --------- --------- ---------
Net operating margins (3,467,761) 3,868,979 7,392,551 8,052,060 6,619,263
Nonoperating margins 1,451,611 1,670,157 2,287,227 1,615,374 2,111,141
--------- --------- --------- --------- ---------
Assignable margins $(2,016,150) $5,539,136 $9,679,778 $9,667,434 $8,730,404
============ ========== ========== ========== ==========
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
---- ----
2002 .92*
2001 1.20
2000 1.39
1999 1.40
1998 1.35
*The 2002 TIER was adversely affected by Order U-01-108(26) we received on
February 6, 2003, from the RCA. See "Management's Discussion and Analysis -
Results of Operations - Overview - Rate Regulation and Rates."
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 all components of providing 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 rates 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. 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 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
interim rate increase was based on a normalized (adjusted for recurring
expenses) test year and a system ratemaking Times Interest Earned Ratio (TIER)
of 1.35. In this filing for permanent rates, we proposed that margins be
calculated using a rate base/rate of return methodology rather than the TIER
methodology previously used.
As anticipated in our July 2001 original filing, on April 15, 2002, we
submitted a filing with the RCA to update certain known and measurable costs and
savings that had occurred outside the 2000 Test Year. In the updated filing, we
reduced our base rate increase request from 6.5% to 5.7%, or approximately $0.9
million in the revenue requirement on a system basis. The revised filing also
reflected an increase in depreciation expense of approximately $1.5 million due
to the completion of the Beluga Unit 7 re-powering project and a reduction in
annualized interest expense, due to our recent refinancing efforts, of $2.4
million. In this revised filing, we continued to request $11.9 million in
margins. As a result of reduced interest costs, this would yield an equivalent
system TIER of 1.47.
On February 6, 2003, we received Order U-01-108(26) from the RCA, which
among other things included the following:
o We will be required to use TIER in calculating return levels.
Our system overall TIER was revised downward from 1.35 to
1.30, a difference that would reduce margins by approximately
$1.3 million based on the 2000 test year and that would also
have similar impacts in subsequent years.
o We will be required to treat AFUDC/IDC as a reduction to
long-term interest expense, which reduced the revenue
requirement by approximately $1.2 million in 2002.
o The RCA reduced our normalized interest rate on our variable
rate debt of 3.8% to 2%, which equates to a revenue
requirement reduction of approximately $1.1 million.
o Our overall Depreciation Study was approved, although the RCA
did require approximately $0.7 million in downward
adjustments, which will not affect margins in future years.
There are several outstanding questions regarding interpretation of the
Order that have not yet been clarified. However, based upon our analysis, the
Order would require a refund of revenues collected in 2001 of approximately $1.1
million and of revenues collected in 2002 of approximately $6.0 million, which
amounts were recorded as a reduction to operating revenues in 2002. The ultimate
amount, which may be refunded, may change based upon RCA's reconsideration of
the Order and we cannot predict the outcome of reconsideration of the issues
inherent in the Order.
The Order would also require a reduction in estimated 2003 revenues of
approximately $6.0 million. Chugach has calculated, that based on the budgeted
revenues and expenditures, under Order 26, Chugach may have insufficient margins
to yield margins for interest equal to at least a 1.10 in 2003.
The CoBank Master Loan Agreement requires us to establish and collect
rates reasonably expected to yield margins for interest equal to at least 1.10
times interest expense. CoBank waived the rate covenant as of December 31, 2002,
and has agreed to reduce the rate covenant for 2003 from 1.10 to 1.08 if the RCA
fails to modify the Order to allow us to set rates sufficient to enable us to
generate margins for interest equal to at least 1.10 times interest charges.
CoBank's prospective modification of the rate covenant for 2003 is contingent
upon Chugach promptly pursuing legal action to force the RCA to modify the Order
to allow us to satisfy the rate covenant as originally written in the CoBank
loan agreement. We intend to pursue such legal action if the RCA fails to modify
the Order, and we believe that we will achieve compliance with the covenant as
revised. The Amended and Restated Indenture also requires us, 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. If there occurs any material change in the circumstances
contemplated at the time rates were most recently reviewed, the Amended and
Restated Indenture requires us to seek appropriate adjustments to those rates so
that they would generate revenues reasonable expected to yield margins for
interest equal to at least 1.10 times interest charges, subject to any necessary
regulatory approval or determination.
In order to maintain our compliance with these covenants, we are taking
the actions described below:
o On February 13, 2003, we filed a Motion with the RCA asking
the RCA to stay the effect of its Order until after the RCA
considers our Petition for Reconsideration of Order 26.
o On February 18, 2003, the RCA granted, in part, our motion for
stay. Specifically, the RCA stayed, until further order of
the RCA, Ordering Paragraph 1 of Order U-01-108(26) which
states, "Chugach's rates will be established on the basis
of the 2000 test year revenue requirement recomputed in
accordance with our decisions set out in the body of this
Order." The RCA stayed the two Ordering paragraphs of the
Order that would have required us to put the new rates into
effect. The RCA also allowed a one-week extension until
February 28, 2003, to comply with ordering paragraphs 2 and 3,
which require us to recalculate our revenue requirement and
cost-of-service studies reflecting the impact of Order
U-01-108(26) on our rates. The RCA also extended the time to
file Petitions for Reconsideration of Order U-01-108(26) one
week to February 28, 2003. We filed the Petition for
Reconsideration with the RCA on February 28, 2003. The Public
Advocacy Section (PAS), also filed a Petition for
Reconsideration that, in part, seeks to remove, from
depreciation expense that the RCA allowed, certain
depreciation associated with Beluga Units 6 and 7 because the
plant was added outside the 2000 Test Year upon which the
rates were based. The RCA issued an Order on March 4,
2003, extending the time for filing responses to petitions for
reconsideration from March 10 to March 14, 2003, and
determined that the period for ruling on the petitions for
reconsideration should be extended from March 31 to April
15, 2003. Management is uncertain as to the outcome but will
vigorously defend its position. Under Alaska law, our
financial covenants in the Amended and Restated Indenture are
valid and enforceable, and rates set by the RCA must be
adequate to meet those covenants. If the RCA does not modify
the Order to allow Chugach to charge rates reasonably expected
to yield margins for interest equal to at least 1.10 times
interest expense, Chugach intends to bring action to enforce
that provision of the Alaska state law described above.
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
had until April 1, 2002, to file a request for reconsideration and until April
15, 2002, to file an appeal. Neither were filed by any party regarding this
order. No additional test years remain to be reviewed under the Settlement
Agreement.
Our base rate changes, excluding fuel surcharges, for retail and
wholesale classes, for the years 2000 through 2002 were as follows:
2002* 2001* 2000
----- ----- ----
Retail 0.00% 3.97% 0.00%
Wholesale:
HEA 0.00% 3.97% (0.70%)
MEA 0.00% 3.97% (0.80%)
Seward 0.00% 0.00% 0.00%
* The 2001 base rate increase was not applied to small general service or
lighting customer classes. Base rates in 2002 did not change, however,
pending the final outcome of Order 26 in Docket U-01-108, Chugach may be
required to issue refunds for sales made during 2001 and 2002.
The rate reductions shown in the table for Matanuska Electric
Association (MEA) and Homer Electric Association (HEA) in 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. Early in 2000, we issued 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 had until April 1, 2002, to
file a request for reconsideration and until April 15, 2002, to file an appeal.
Neither were filed by any party regarding this order. No additional test years
remain to be reviewed under the Settlement Agreement.
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. In a decision issued on November 15, 2002, the
Alaska Supreme Court affirmed the decision of the Superior Court. Chugach is no
longer required to issue refunds associated with fuel surcharge.
Year ended December 31, 2002 compared to the years ended December 31,
2001 and 2000
Margins
Our margins for the years ended December 31, 2002, 2001 and 2000, were
as follows:
2002 2001 2000
---- ---- ----
Net Operating Margins $ (3,467,761) $3,868,979 $7,392,551
Nonoperating Margins $ 1,451,611 $1,670,157 $2,287,227
----------- ---------- ----------
Assignable Margins $ (2,016,150) $5,539,136 $9,679,778
============= ========== ==========
The decrease in assignable margins in 2002 of $7.6 million, or 136%,
was due to the provision for rate refunds Chugach was required to record as a
result of RCA Order U-01-108(26). The decrease in assignable margins in 2001 of
$4.1 million, or 43%, was 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 2002 from 2001 by $219,000, or 13%, due to
lower interest income rates, as well as a decrease in allocations of patronage
capital from CoBank. 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.
Revenues
Operating revenues include sales of electric energy to retail,
wholesale and economy energy customers and other miscellaneous revenues. In
2002, operating revenues were $6.7 million, or 4%, lower than in 2001 due to a
$7.1 million provision for rate refund we recorded in 2002, calculated based on
the requirements set forth in RCA Order U-01-108(26). In addition, recoverable
fuel and purchased power expenses were lower in 2002 due to lower fuel prices.
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. The major components of our operating
revenue for the year ended December 31, 2002, 2001, and 2000 were as follows:
2002 2001 2000
---- ---- ----
Retail $110,082,014 $112,026,122 $98,536,690
Wholesale
HEA 22,035,973 24,260,072 19,060,244
MEA 30,018,227 33,706,678 27,252,051
Seward 2,709,752 2,816,970 2,369,550
Economy energy 4,567,179 3,354,719 7,820,998
Other 2,531,773 2,430,653 3,501,581
--------- --------- ---------
Total revenue $171,944,918 $178,595,214 $158,541,114
============ ============ ============
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 2002, 2001, and 2000,
economy sales to GVEA constituted approximately 2.7%, 1.9%, and 5.0%,
respectively, of our sales revenues. The increase in economy sales in 2002 from
2001 was due to GVEA's higher fuel prices than Chugach's, which made it more
economical for GVEA to purchase power from Chugach rather then generate its own.
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.
Expenses
The major components of our operating expenses for the years ended
December 31, 2002, 2001 and 2000 were as follows:
2002 2001 2000
---- ---- ----
Fuel $46,822,943 $56,130,437 $42,504,396
Other power production 13,500,103 12,397,465 10,221,978
Purchased power 18,750,936 14,717,318 9,152,248
Transmission 3,930,902 3,545,707 3,828,630
Distribution 10,869,335 10,417,736 9,774,860
Consumer accounts 5,594,572 5,121,394 5,275,455
Sales expense 0 495,523 1,112,804
Administrative, general and other 22,251,895 19,574,476 21,343,393
Depreciation 27,649,250 25,096,665 23,216,509
---------- ---------- ----------
Total operating expenses $149,369,936 $147,496,721 $126,430,273
============ ============ ============
Fuel expense decreased by $9.3 million, or 17%, in 2002 from 2001 due
to lower fuel prices, as well as lower volume purchases. This category increased
from 2000 to 2001 due to higher fuel prices and higher volume purchases. Other
power production expense increased in 2002 from 2001 by $1.1 million, or 9%, due
primarily to scheduled maintenance and inspections on multiple units at Beluga
and Bernice Lake. Other power production expense increased in 2001 from 2000 by
$2.2 million, or 21%, due to an increase in fuel expense, as well as the use of
less efficient units in order to meet demand while Beluga unit 6 and unit 7 were
unavailable.
Purchased power costs increased by $4.0 million, or 27%, from 2001 to
2002 due to the full year impact of the new contract with AEG&T/HEA regarding
Nikiski unit 1 and also a slight increase in the cost of power from Bradley Lake
due to operation and maintenance activities. Purchased power costs increased by
$5.6 million, or 61%, from 2000 to 2001 due to the normally idle Soldotna #1
power plant being taken out of service and relocated to Nikiski where it was
operated for the remainder of the year as a base load unit.
Transmission expense increased in 2002 from 2001 by $385,000, or 11%,
due to an increase in patrolling of the 138kV and 230kV lines, bird nest
removals and supporting rod replacements. Transmission expense did not vary
materially in 2001 from 2000.
Distribution expense increased in 2002 from 2001 by $452,000, or 4%,
due to an increase in trouble calls relating to outages and damage claims. In
addition, expenses were higher due to an increase in the number of locates
associated with an increase in local construction activity. Distribution
substation maintenance also increased due to problems discovered while utilizing
new predictive maintenance technology at multiple substations. 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.
Consumer accounts expense increased by $473,000, or 9%, from 2001 to
2002, due to increased costs associated with billing and remittance processing
as well as increased bank and credit card fees. There was also a shift in the
activities of the Marketing Department from sales to customer information
activities. Consumer accounts expense did not vary materially from 2000 to 2001.
Sales expense decreased by $496,000, or 100% in 2002 from 2001, due to
the elimination of the Marketing Department in mid-2002. 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.
Administrative, general and other expenses increased by $2.7 million,
or 14% in 2002 from 2001, due to increased consulting and outside counsel
expenses related to the 2000 Test Year rate case. In addition, a liability for
our National Rural Electric Cooperative Association (NRECA), past service cost
adjustment was expensed in 2002. Insurance costs recorded in 2002 were also
higher than in 2001. 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.
We use remaining life rates set forth in the most recently approved
depreciation study. Depreciation expense increased in 2002 from 2001 by $2.6
million, or 10%, due to an increase in capitalized plant, as well as the
implementation of new depreciation rates, effective January 1, 2002, as a result
of RCA Order U-01-108(26). 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.
Interest on long-term obligations decreased by $967,000, or 4% in 2002
from 2001, due to the refinancing completed in February 2002 and lower interest
rates. Interest on long-term obligations increased in 2001 from 2000 by $2.1
million, or 9%, due to the public bond offering in April 2001. Interest on
short-term obligations decreased by $866,000, or 74% in 2002 from 2001, due to a
decrease in short-term borrowing, as well as decreased interest rates. 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 charged to
construction decreased in 2002 from 2001 by $646,000, or 61%, due to a lower
average balance in Construction Work in Progress and lower interest rates. There
was a decrease in interest charged to construction due to a decrease in
construction projects from 2000 to 2001. Net interest expense includes interest
on long-term obligations and short-term obligations, reduced by interest charged
to construction. The above mentioned decreases were slightly offset by the
write-off of the gain on the 1991 refinanced debt against the premium paid to
refinance in February of 2002, as well as the associated transaction costs.
Patronage Capital (Equity)
Our patronage capital and total equity had shown steady growth until
this year. The following table summarizes our patronage capital and total equity
position for the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000
---- ---- ----
Patronage capital at beginning of year $125,184,374 $122,925,253 $117,335,481
Retirement of capital credits
and estate payments (3,019,722) (3,280,015) (4,090,006)
Assignable margins (2,016,150) 5,539,136 9,679,778
----------- --------- ---------
Patronage capital at end of year 120,148,502 125,184,374 122,925,253
Other equity 7,329,393 6,624,332 5,890,087
--------- --------- ---------
Total equity at end of year $127,477,895 $131,808,706 $128,815,340
============ ============ ============
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, 2002, 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 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. In December 2002, we distributed
$2,769,568 of patronage capital to our members.
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 Total
2003 $0
2004 405,000
2005 1,260,000
2006 400,000
2007 1,600,000
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 decreased by $5.1 million, or 1%, from December 31, 2001,
to December 31, 2002. The net decrease was primarily due to an increase in
accumulated depreciation due to substantial plant capitalized in prior periods,
as well as a $2.3 million increase to reflect new rates established in the 1999
depreciation study that we were required to implement by RCA Order U-01-108(26).
There was also a decrease of the under-recovery in the fuel surcharge balancing
account in the fourth quarter of 2002. This decrease was offset by an increase
in cash and cash equivalents and an increase in accounts receivable due to
several large billings to the State of Alaska for completed projects, as well as
wholesale power bills that were accrued but not paid by December 31, 2002. This
was also offset by an increase in prepayments due to the prepayment of rotors
for Beluga 6 and 7 that are due to be installed in 2003 and 2004.
Changes in total liabilities include the increase in long-term
obligations due to the public bond offering in February 2002. This increase was
offset by a decrease in current installments of long-term obligations due to the
payment of the first installment of CoBank 5 that was paid in June of 2002, as
well as a decrease in short-term obligations. There was also a decrease in fuel
payable due to lower fuel prices in 2002, as compared to 2001. Accrued interest
also decreased due to lower interest rates on our debt due to our re-financing
efforts in early 2002. Deferred credits also decreased due to the payment of the
premium that offset the gain associated with the 1991 Series A Bond due 2022
that was refinanced in the first quarter of 2002.
Patronage capital decreased by $2.8 million due to the capital credit
retirement in the fourth quarter of 2002, as well as the $2.0 million loss as a
result of RCA Order U-01-108(26).
Contractual Obligations and Commercial Commitments
The following are Chugach's contractual and commercial commitments as
of December 31, 2002:
Contractual cash obligations: (In thousands)
Payments Due By Period
Total 2003 2004-2005 2006-2007 Thereafter
Long-term debt $395,000 $5,166 $21,476 $18,054 $350,304
Short-term debt* 6,081 6,081 0 0 0
----- ----- - - -
Total $401,081 $11,247 $21,476 $18,054 $350,304
Commercial Commitments: (In thousands)
Amount of Commitment
Expiration Per Period
Total 2002 2003-2004 2005-2006 Thereafter
Lines of credit-available * $64 $64 $0 $0 $0
*At December 31, 2002, Chugach had $70 million in lines of credit available with
various financial institutions, which fund capital requirements. At December 31,
2002, $6.1 million was outstanding, effectively reducing the available borrowing
capacity under these lines of credit to $64 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 NRUCFC,
which was renewed for a five year term on October 15, 2002, and a $20 million
line of credit with CoBank. At December 31, 2002, there was no outstanding
balance with CFC. As of December 31, 2002, $6.1 million was outstanding under
the CoBank line of credit. This line of credit bears interest at a variable
rate, which was 3.17% as of December 31, 2002, and is currently 3.08% as of
March 2003.
On April 17, 2001, we issued $150 million 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 million, 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 $72.5 million, 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 bears
interest at 6.55% per annum. Interest is payable semi-annually on March 15
and September 15 of each year commencing on September 15, 2001.
On February 1, 2002, we issued $120 million of 2002 Series A Bond
and $60 million 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 bears interest at 6.20% per annum. Interest is
payable 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 bore interest from the date of
original delivery to and through February 27, 2002, at a rate established by
the underwriter prior to its date of delivery and thereafter bore interest
at the rate set for 28-day auction periods. The initial auction took place
on February 27, 2002. The applicable interest rate for any 28-day auction
period is 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.
The 2001 Series A Bond, the 2002 Series A Bond and the Auction Rate
Bond are unsecured obligations, ranking equally with our other unsecured and
unsubordinated obligations. In addition, we are limited in our ability to
secure obligations for borrowed money or the deferred purchase price of
property unless we equally and ratably secure our outstanding indebtedness
subject to the Amended and Restated Indenture governing our Bonds.
Principal maturities and sinking fund payments of our outstanding
indebtedness at December 31, 2002 are set forth below:
Year Ending Sinking Fund Principal maturities
December 31 Requirement Total
2003 $4,300,000 $865,821 $5,165,821
2004 4,600,000 945,000 5,545,000
2005 4,900,000 11,031,393 15,931,393
2006 5,200,000 1,125,687 6,325,687
2007 5,500,000 6,228,569 11,728,569
Thereafter 305,500,000 44,803,530 350,303,530
----------- ---------- -----------
$330,000,000 $65,000,000 $395,000,000
============ =========== ============
During 2002 we spent approximately $16.4 million on capital
construction projects, net of reimbursements, 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 capital
improvement program. Set forth below is an estimate of capital expenditures for
the years 2003 through 2007:
2003 $33.3 million
2004 $37.7 million
2005 $32.6 million
2006 $33.4 million
2007 $26.0 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 and an
overhaul of Beluga unit 7.
We expect that cash flows from operations and external funding sources
will be sufficient to cover operational and capital funding requirements in 2003
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 us to our customers are based upon cost basis regulation reviewed and
approved by this regulatory commission. Under the authority of this commission,
we have recorded certain regulatory assets in the amount of $22.1 million as of
December 31, 2002. If our 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
Chugach uses U.S. Treasury forward rate lock agreements to hedge
expected interest rates on debt. We 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, which was authorized by the RCA in Order U-01-108(26). 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.
Critical estimates also include provision for rate refunds and
allowance for doubtful accounts. Actual results could differ from those
estimates.
Item 7A - Quantitative and Qualitative Disclosures
About Market Risk
Chugach is 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, 2002, other than the 2002 Series B Bond, 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, 2002, and 2001:
2002
Fair
Total Debt* 2003 2004 2005 2006 2007 Thereafter Total Value
- ----------- ---- ---- ---- ---- ---- ---------- ----- -----
Fixed rate $866 $945 $11,031 $1,126 $6,228 $314,804 $335,000 $365,279
Average
interest rate 5.60% 5.60% 7.56% 5.60% 5.60% 6.27% 6.29%
Variable rate $10,381 $4,600 $4,900 $5,200 $5,500 $35,500 $66,081 $66,081
Average
interest rate 2.44% 1.40% 1.40% 1.40% 1.40% 1.40% 1.56%
* Includes current portion
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%
* Includes current portion
Chugach is 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 $103,810, based on $10,381,000 of variable debt outstanding at
December 31, 2002. The CoBank and CFC lines of credit, under which we currently
have $6.1 million in short-term debt outstanding, bear interest at variable
rates.
To manage interest rate exposure for refinancing the 1991 Series A Bond
due 2022, 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 had 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. On January 14, 2002, we entered into an 18-day rate lock agreement
with JP Morgan on the $120 million 10-year term bond of the proposed 2002
refinancing. We terminated the rate lock on February 1, 2002, which generated a
payment to us of $1.2 million. All of the settlement payments were accounted for
as regulatory assets and amortized over the life of the corresponding debt,
which was authorized by the RCA in Order U-01-108(26).
Commodity Price Risk
Chugach's 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, 2002 and 2001
Independent Auditors' Report
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association,
Inc. (Chugach) as of December 31, 2002 and 2001, 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, 2002. These financial statements are
the responsibility of the Chugach'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, 2002 and 2001, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2002 in conformity with accounting principles generally accepted in the United
States of America.
/s/ KPMG, LLP
Anchorage, Alaska
March 11, 2003
Chugach Electric Association, Inc.
Balance Sheets
December 31, 2002 and 2001
Assets 2002 2001
------ ---- ----
Utility plant (notes 2, 6, 12 and 13):
Electric plant in service $730,439,297 $714,317,863
Construction work in progress 20,224,302 28,887,008
---------- ----------
750,663,599 743,204,871
Less accumulated depreciation 279,958,912 261,353,177
----------- -----------
Net utility plant 470,704,687 481,851,694
Other property and investments, at cost:
Nonutility property 3,550 3,550
Investments in associated organizations (note 3) 10,963,715 10,485,186
---------- ----------
10,967,265 10,488,736
Current assets:
Cash and cash equivalents, including repurchase agreements of $8,007,424
in 2002 and $5,520,275 in 2001
7,284,292 3,814,767
Cash-restricted construction funds 598,864 517,871
Special deposits 222,163 222,163
Accounts receivable, less provision for doubtful accounts of $313,545
in 2002 and $318,757 in 2001 26,410,264 22,302,400
Fuel cost recovery 0 3,591,963
Materials and supplies 23,747,590 22,822,003
Prepayments 1,953,350 627,544
Other current assets 336,798 335,753
------- -------
Total current assets 60,553,321 54,234,464
Deferred charges (notes 9 and 14) 27,989,601 28,706,293
---------- ----------
$570,214,874 $575,281,187
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Balance Sheets, Continued
December 31, 2002 and 2001
Liabilities & Equities 2002 2001
---------------------- ---- ----
Equities and margins (note 5):
Memberships $1,108,243 $1,059,098
Patronage capital (note 4) 120,148,502 125,184,374
Other (note 5) 6,221,150 5,565,234
--------- ---------
127,477,895 131,808,706
Long-term obligations, excluding current installments (notes 6, 7 and 17):
2001 Series A Bonds payable 150,000,000 150,000,000
2002 Series A Bonds payable 120,000,000 0
2002 Series B Bonds payable 55,700,000 0
First Mortgage (1991 Series A) Bonds payable 0 149,310,000
National Bank for Cooperatives Promissory Notes payable 64,134,179 65,000,000
---------- ----------
389,834,179 364,310,000
Current liabilities:
Current installments of long-term obligations (notes 6 and 7) 5,165,821 10,409,945
Short-term obligations (note 6) 6,081,250 11,000,000
Accounts payable 7,719,974 11,012,905
Provision for rate refund (note 17) 7,050,000 0
Consumer deposits 1,826,265 1,603,691
Fuel cost payable 363,862 0
Accrued interest 6,381,106 7,378,058
Salaries, wages and benefits 4,977,594 4,844,819
Fuel 7,095,402 11,565,117
Other current liabilities 2,027,938 1,900,155
--------- ---------
Total current liabilities 48,689,212 59,714,690
Deferred credits (note 11) 4,213,588 19,447,791
--------- ----------
$570,214,874 $575,281,187
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Revenues, Expenses and Patronage Capital
Years ended December 31, 2002, 2001 and 2000
2002 2001 2000
---- ---- ----
Operating revenues (note 17) $171,944,918 $178,595,214 $158,541,114
Operating expenses:
Fuel 46,822,943 56,130,437 42,504,396
Other power production 13,500,103 12,397,465 10,221,978
Purchased power 18,750,936 14,717,318 9,152,248
Transmission 3,930,902 3,545,707 3,828,630
Distribution 10,869,335 10,417,736 9,774,860
Consumer accounts 5,594,572 5,121,394 5,275,455
Sales expense 0 495,523 1,112,804
Administrative, general and other 22,251,895 19,574,476 21,343,393
Depreciation 27,649,250 25,096,665 23,216,509
---------- ---------- ----------
Total operating expenses 149,369,936 147,496,721 126,430,273
Interest expense:
On long-term obligations 26,161,891 27,128,662 24,987,033
Charged to construction - credit (418,078) (1,063,643) (2,178,425)
On short-term obligations 298,930 1,164,495 1,909,682
------- --------- ---------
Net interest expense 26,042,743 27,229,514 24,718,290
---------- ---------- ----------
Net operating margins (3,467,761) 3,868,979 7,392,551
Nonoperating margins:
Interest income 774,814 679,640 703,807
Other 897,761 1,236,907 1,615,161
Property loss (220,964) (246,390) (31,741)
--------- --------- --------
Assignable margins (2,016,150) 5,539,136 9,679,778
Patronage capital at beginning of year 125,184,374 122,925,253 117,335,481
Retirement of capital credits and estate payments (note 4) (3,019,722) (3,280,015) (4,090,006)
----------- ----------- -----------
Patronage capital at end of year $120,148,502 $125,184,374 $122,925,253
============ ============ ============
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Cash Flows
Years ended December 31, 2002, 2001 and 2000
2002 2001 2000
---- ---- ----
Operating activities:
Assignable margins $(2,016,150) $5,539,136 $9,679,778
Adjustments to reconcile assignable margins to net cash
provided by operating activities:
Provision for rate refund 7,050,000 0 0
Depreciation and amortization 33,472,159 30,265,821 27,575,408
Capitalization of interest (491,349) (1,370,319) (340,838)
Property (gains) losses, net (220,964) (246,390) (31,741)
Other 1,568 (19,169) (1,155)
Changes in assets and liabilities:
(Increase) decrease in assets:
Special deposits 0 (10,000) (29,999)
Accounts receivable (4,107,864) (3,101,488) (1,469,918)
Fuel cost recovery 3,591,963 (676,230) (2,734,978)
Prepayments (1,325,806) 127,732 106,671
Materials and supplies (925,587) (7,464,805) 1,822,938
Deferred charges (4,479,028) (13,761,107) (1,231,531)
Other assets (1,044) (3,507) 9,456
Increase (decrease) in liabilities:
Accounts payable (3,292,931) 1,519,030 (14,976)
Fuel payable 363,862 0 0
Accrued interest (996,952) 1,516,668 (204,724)
Deferred credits (14,580,533) (1,584,906) (3,638,491)
Consumer deposits 222,574 279,478 264,536
Other liabilities (4,209,158) 4,134,563 3,213,198
----------- --------- ---------
Net cash provided by operating activities 8,054,760 15,144,507 32,973,634
Investing activities:
Extension and replacement of plant (16,417,119) (36,408,253) (46,730,043)
Increase in investments in associated organizations (480,097) (608,864) (909,137)
--------- --------- ---------
Net cash used in investing activities (16,897,216) (37,017,117) (47,639,180)
Financing activities:
Net transfer of restricted construction funds (80,993) (139,023) 159,556
Proceeds from short-term borrowings, net 0 (29,000,000) 40,000,000
Proceeds from long-term obligations 180,000,000 150,000,000 0
Repayments of long-term obligations (164,638,695) (93,930,350) (24,872,405)
Memberships and donations received 705,061 734,245 700,923
Retirement of patronage capital (3,019,722) (3,280,015) (4,090,006)
Net receipts (refunds) of consumer advances for construction (653,670) (392,642) 352,610
--------- --------- -------
Net cash provided by financing activities 12,311,981 23,992,215 12,250,678
---------- ---------- ----------
Net change in cash and cash equivalents 3,469,525 2,119,605 (2,414,868)
Cash and cash equivalents at beginning of year $3,814,767 $1,695,162 $4,110,030
---------- ---------- ----------
Cash and cash equivalents at end of year $7,284,292 $3,814,767 $1,695,162
========== ========== ==========
Supplemental disclosure of cash flow information
Interest expense paid, net of amounts capitalized $27,039,695 $25,712,846 $24,917,014
=========== =========== ===========
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2002 and 2001
(1) Description of Business and Summary of Significant Accounting Policies
Description of Business
Chugach Electric Association, Inc., (Chugach) is the largest electric
utility in Alaska. Chugach is engaged in the generation, transmission and
distribution of electricity to directly served retail customers in the
Anchorage and upper Kenai Peninsula areas. Through an interconnected
regional electrical system, Chugach's power flows throughout Alaska's
Railbelt, a 400-mile-long area stretching from the coastline of the
southern Kenai Peninsula to the interior of the state, including Alaska's
largest cities, Anchorage and Fairbanks.
Chugach also supplies much of the power requirements of three wholesale
customers, Matanuska Electric Association (MEA), Homer Electric
Association (Homer) and the City of Seward (Seward). Chugach's members
are the consumers of the electricity sold.
Chugach 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. Chugach is subject to the regulatory authority of
the Regulatory Commission of Alaska (RCA).
Management Estimates
In preparing the financial statements, management of Chugach 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. Critical estimates include the provision for rate refund and
allowance for doubtful accounts. Actual results could differ from those
estimates.
Regulation
The accounting records of Chugach conform to the Uniform System of
Accounts as prescribed by the Federal Energy Regulatory Commission
(FERC). Chugach 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
Chugach's statement of revenues and expenses as assignable margins. These
excess amounts (i.e. assignable margins) are considered capital furnished
by the members, and are credited to their accounts and held by Chugach
until such future time as they are retired and returned without interest.
Retained assignable margins are designated on Chugach's balance sheet as
patronage capital. This patronage capital constitutes the principal
equity of Chugach.
(1) Description of Business and Summary of Significant Accounting Policies
(continued)
Reclassifications
Certain reclassifications, which have no affect on assignable margins,
have been made to the 2000 and 2001 financial statements to conform to
the 2002 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. Chugach's tariffs
include provisions for the flow through of gas costs according to
existing gas supply contracts. Chugach recorded potential refunds of
approximately $7.1 million as described in note 17, "Subsequent Events -
Regulation."
Chugach entered into a settlement agreement with MEA and Homer in 1996.
The settlement agreement was designed to resolve a number of ratemaking
disputes and assure MEA and Homer that their base rates would be no
higher than those based on 1995 costs and would be reduced (and refunds
given) if Chugach's 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. Early in
2000, refunds of $86,132 were issued to Homer and $1,809,801 to MEA that
represented uncontested amounts owed consistent with the 1996 test year
filing. In June 2000, the RCA issued its final order approving the 1996
test year cost of service. As a result of this order, additional refunds
were issued to MEA and Homer in the amounts of $332,157 and $503,272,
respectively, on July 25, 2000. Consistent with the Settlement Agreement,
these refunds were based on demand and energy purchases retroactive to
January 1, 1997.
(1) Description of Business and Summary of Significant Accounting Policies
(continued)
The RCA issued an order for the 1997 test year that did not reduce
wholesale rates or require refunds under the Settlement Agreement.
Chugach submitted its 1998 test year revenue requirement filing to the
RCA in February 2001. According to an order issued by the RCA on March
15, 2002, no rate reduction or refunds were required based on Chugach's
1998 test year costs. Parties had until April 1, 2002, to file a request
for reconsideration and until April 15, 2002, to file an appeal. Neither
were filed by any party regarding this order. No additional test years
remain to be reviewed under the Settlement Agreement.
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 11, 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. The
RCA's approval required a revision to the contract to include an option
to re-negotiate the terms of the contract if rates are adjusted by the
2000 Test Year general rate case. Seward has three choices within sixty
days of the final order. 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.
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 had refused to pay the portion of its
monthly bill it considered to be recovery of the Marathon tax. On
December 20, 2000, by the Superior Court for the State of Alaska, MEA was
ordered to pay the unpaid tax liability and associated litigation costs.
MEA appealed that order to the Alaska Supreme Court. On November 15,
2002, the Alaska Supreme Court affirmed the decision of the Superior
Court for the State of Alaska. Chugach invoiced MEA for the unpaid tax
liability and associated litigation costs, as well as interest on the
unpaid balance. On January 8, 2003, Chugach received payment.
(1) Description of Business and Summary of Significant Accounting Policies
(continued)
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, Chugach's financial statements reflect
regulatory assets and liabilities. Continued accounting under SFAS 71
required certain criteria be met. Management believes Chugach'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, 2002 are as follows:
Annual Depreciation Rate Ranges
Steam production plant 2.55% - 2.80%
Hydraulic production plant 0.04% - 1.56%
Other production plant 2.67% - 7.62%
Transmission plant 1.50% - 4.24%
Distribution plant 2.13% - 9.22%
General plant 2.21% - 20.40%
Other 2.35% - 2.75%
(1) Description of Business and Summary of Significant Accounting Policies
(continued)
Chugach uses remaining life rates set forth in the most recently approved
depreciation study. In 2000 an update of the Depreciation Study was
completed utilizing Electric Plant in Service balances as of December 31,
1999. Depreciation rates developed in that study were implemented
effective January 1, 2002, in accordance with the RCA's Order No. 26,
"Order Determining Revenue Requirement and Rate Design Issues and
Requiring Filings" in Docket U-01-108, "In the Matter of the Tariff
Revision, Designated as TA226-8, Filed by CHUGACH ELECTRIC ASSOCIATION,
INC." (Order U-01-108(26) or the Order)
Capitalized Interest
Allowance for funds used during construction (AFUDC) and interest charged
to construction (IDC) - credit are the estimated costs during the period
of construction of equity and borrowed funds used for construction
purposes. Chugach capitalized such funds at the weighted average rate
(adjusted monthly) of 4.7% during 2002, 7.5% during 2001 and 7.9% during
2000.
Cash and Cash Equivalents
For purposes of the statement of cash flows, Chugach considers all highly
liquid debt instruments with a maturity of three months or less upon
acquisition by Chugach (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.
(1) Description of Business and Summary of Significant Accounting Policies
(continued)
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
Chugach used U.S. Treasury forward rate lock agreements to hedge
expected interest rates on the February 2002 debt re-financings. Chugach
accounted for the agreements under SFAS 80 and 71 through December 31,
2000, and SFAS 133, 138 and 71 subsequent to that date. Chugach adopted
SFAS 133 on January 1, 2001. Accordingly, the unrealized gain or loss
was not recorded and was treated as a regulatory asset upon settlement
(note 6). This accounting treatment was approved by the RCA in Order
U-01-108(26). See note 17, "Subsequent Events - Regulation."
Income Taxes
Chugach 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, 2002, 2001 and 2000
Chugach received no unrelated business income.
Environmental Remediation Costs
Chugach 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:
2002 2001
---- ----
Electric plant in service:
Steam production plant $60,392,869 $60,392,869
Hydraulic production plant 17,904,105 8,125,226
Other production plant 103,046,773 94,207,814
Transmission plant 208,103,602 206,972,504
Distribution plant 188,775,770 177,457,788
General plant 52,273,770 46,757,035
Unclassified electric plant in service* 91,346,892 111,809,111
Equipment under capital lease 56,323 56,323
Other 8,539,193 8,539,193
--------- ---------
Total electric plant in service 730,439,297 714,317,863
Construction work in progress 20,224,302 28,887,008
---------- ----------
Total electric plant in service and
construction work in progress $750,663,599 $743,204,871
============ ============
*Unclassified electric plant in service consists of complete unclassified of general plant, generation, transmission and
distribution projects
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, which are non-marketable and
accounted for at cost, include the following at December 31:
2002 2001
---- ----
National Rural Utilities Cooperative Finance
Corporation (NRUCFC) $6,095,980 $6,095,980
National Bank for Cooperatives (CoBank) 4,703,331 4,216,115
NRUCFC capital term certificates 44,631 45,616
Other 119,773 127,475
------- -------
$10,963,715 $10,485,186
=========== ===========
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. Chugach's investment in NRUCFC similarly was required by
Chugach's financing arrangements with NRUCFC.
(4) Patronage Capital
Chugach 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 Chugach's assignable
margins on an approximately 15-year rotation. At December 31, 2002,
Chugach had assigned $122,164,652 of patronage capital (net of capital
credit retirements). Approval of actual capital credit retirements is at
the discretion of Chugach's Board of Directors.
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.
(4) Patronage Capital (continued)
In November 2002, the Board of Directors authorized the retirement of
$2,769,568 of retail patronage for 1985.
Estate payments in the amount of $250,154, $280,015 and $340,006 were
made in 2002, 2001 and 2000, respectively.
Following is a five-year summary of anticipated capital credit
retirements:
Year ending Total
December 31,
2003 $0
2004 405,000
2005 1,260,000
2006 400,000
2007 1,600,000
(5) Other Equities
A summary of other equities at December 31 follows:
2002 2001
---- ----
Nonoperating margins, prior to 1967 $23,625 $23,625
Donated capital 183,807 183,907
Unredeemed capital credit retirement 6,013,718 5,357,702
--------- ---------
$6,221,150 $5,565,234
(6) Debt
Long-term obligations at December 31 are as follows: 2002 2001
---- ----
2002 Series A Bond of 6.20%, maturing in 2012, with interest payable
semi-annually February 1 and August 1: $120,000,000 $0
2002 Series B Bond of a rate set for 28-day auction periods, maturing in
2012, with interest payable monthly and principal due annually 60,000,000 0
2001 Series A Bond of 6.55%, maturing in 2011, with interest payable
semi-annually March 15 and September 15: 150,000,000 150,000,000
First mortgage (1991 Series A) Bond of 8.08%, that matured in 2002 and
9.14% that would have matured in 2022, with interest that was payable
semi-annually March 15 and September 15:
8.08% 0 5,232,000
9.14%(refinanced in 2002 by the 2002 Series A and Series B Bond, maturing
in 2012) 0 149,310,000
CoBank 8.95% bond that matured in 2002, with interest that was payable
monthly and principal that was due semi-annually 0 177,945
CoBank 7.76% note maturing in 2005, with interest payable monthly 10,000,000 10,000,000
CoBank 5.60% note maturing in 2022, with interest payable monthly and
principal due annually beginning in 2003 45,000,000 45,000,000
CoBank 5.60% note, with principal due in 2007 and 2012, and with interest
payable monthly 10,000,000 15,000,000
---------- ----------
Total long-term obligations 395,000,000 374,719,945
Less current installments 5,165,821 10,409,945
--------- ----------
Long-term obligations, excluding current installments $389,834,179 $364,310,000
============ ============
(6) Debt (continued)
Covenants
Chugach is required to comply with all covenants set forth in the Amended
and Restated Indenture, dated April 1, 2001, which became effective
January 22, 2003, and the covenants contained in the Master Loan
Agreement between Chugach and CoBank dated December 27, 2002.
Security
Substantially all assets were pledged as collateral for the long-term
obligations until retirement of the 1991 Series A Bonds and subsequent
institution of the Amended and Restated Indenture. On January 22, 2003,
the Bonds became general unsecured and unsubordinated obligations. Under
the Amended and Restated Indenture, Chugach is prohibited from creating
or permitting to exist any mortgage, lien, pledge, security interest or
encumbrance on Chugach's 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 Chugach
equally and ratably secure all bonds subject to the Amended and Restated
Indenture, except that Chugach may incur secured indebtedness in an
amount not to exceed $5 million or enter into sale and leaseback or
similar agreements.
Rate
The Amended and Restated 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 1.10 times total
interest expense. The CoBank Master Loan Agreement also requires Chugach
to establish and collect rates reasonably expected to yield margins for
interest equal to at least 1.10 times interest expense. As described in
note 17 "Subsequent events - Regulation," Chugach received a waiver of
the rate covenant from CoBank. Margins for interest generally consist of
Chugach's assignable margins plus total interest expense. Chugach's
analysis of the financial impact of Order U-01-108(26) from the RCA is
still preliminary, however, upon recording the adjustments set forth in
Order U-01-108(26), Chugach's margins for interest would fall below 1.10
times interest charges. If there occurs any material change in the
circumstances contemplated at the time rates were most recently reviewed,
the Amended and Restated Indenture requires Chugach to seek appropriate
adjustments to those rates so that they would generate revenues
reasonable expected to yield margins for interest equal to at least 1.10
times interest charges. In order to maintain Chugach's compliance with
this covenant, Chugach is taking the actions described in note 17,
"Subsequent Events - Regulation."
(6) Debt (continued)
Distribution to Members
The Amended and Restated Indenture prohibits Chugach from making any
distribution of patronage capital to Chugach's customers if an event of
default under the Amended and Restated Indenture exists. Otherwise,
Chugach may make distributions to Chugach's members in each year equal to
the lesser of 5% of Chugach's patronage capital or 50% of assignable
margins for the prior fiscal year. This restriction does not apply if,
after the distribution, Chugach's aggregate equities and margins as of
the end of the immediately preceding fiscal quarter are equal to at least
30% of Chugach's total liabilities and equities and margins.
Maturities of Long-term Obligations
Long-term obligations at December 31, 2002, mature as follows:
Year ending
December 31 Sinking Fund Sinking Fund Sinking Fund Principal maturities Total
-------------------- -----
Requirements Requirements Requirements
2001 Series A 2002 Series A 2002 Series B CoBank
Bonds Bonds Bonds Mortgage bonds
2003 $0 $0 $4,300,000 $865,821 $5,165,821
2004 0 0 4,600,000 945,000 5,545,000
2005 0 0 4,900,000 11,031,393 15,931,393
2006 0 0 5,200,000 1,125,687 6,325,687
2007 0 0 5,500,000 6,228,569 11,728,569
Thereafter 150,000,000 120,000,000 35,500,000 44,803,530 350,303,530
----------- ----------- ---------- ---------- -----------
$150,000,000 $120,000,000 $60,000,000 $65,000,000 $395,000,000
============= ============= ============ =========== ============
Short-term obligations
Chugach had an annual line of credit of $35,000,000 available in 2001 and
2002 with CoBank. On December 27, 2002, Chugach chose to reduce the
available line of credit to $20,000,000. The CoBank line of credit
expires July 31, 2003. At December 31, 2002, there was $6.1 million
outstanding on this line of credit, which carried an interest rate of
(6) Debt (continued)
3.17%. At December 31, 2001, there was $11 million outstanding on this
line of credit, which carried an interest rate of 3.75%. In addition,
Chugach had an annual line of credit of $50,000,000 available at December
31, 2002 and 2001 with NRUCFC. At December 31, 2002 and 2001, there was
no outstanding balance on this line of credit. The NRUCFC line of credit
expires October 15, 2007.
Refinancing
On February 1, 2002, Chugach issued $120 million of 2002 Series A Bond
and $60 million 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 bears interest at 6.20% per annum.
Interest is payable 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 bore 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 thereafter bore interest
at the rate set for 28-day auction periods. The initial auction took
place on February 27, 2002. The applicable interest rate for any 28-day
auction period is the term rate established by the auction agent based on
the terms of the auction. The Auction Rate Bond may be converted, in
Chugach's 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 is the auction agent and J.P. Morgan
Securities Inc., acted as the initial broker-dealer for the Auction Rate
Bond.
On April 17, 2001, Chugach issued $150 million of 2001 Series A Bond, for
the purpose of retiring indebtedness outstanding under existing lines of
credit and outstanding bonds,
(6) Debt (continued)
for capital expenditures and for general working capital. The lines of
credit had an aggregate outstanding principal balance of $55 million, 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 $72.5 million, 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 bears interest
at 6.55% per annum. Interest is payable semi-annually on March 15 and
September 15 of each year commencing on September 15, 2001. The 2001
Series A Bond, 2002 Series A Bond and Auction Rate Bond are unsecured
obligations, ranking equally with Chugach's other unsecured and
unsubordinated obligations. In addition, Chugach is limited in Chugach's
ability to secure obligations for borrowed money or the deferred purchase
price of property unless Chugach equally and ratably secures Chugach's
outstanding indebtedness subject to the Amended and Restated Indenture
governing its Bonds.
On September 19, 1991, Chugach issued $314 million 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 million (note 11).
The bond that matured in 2002 (1991 Series A 2002 Bond) was subject to
annual sinking fund redemption at 100% of the principal amount thereof,
which commenced March 15, 1993. The bond that would have matured in 2022
(1991 Series A 2022 Bond) was subject to annual sinking fund redemption
at 100% of the principal amount thereof commencing March 15, 2003. The
Series A 2002 Bond was not subject to optional redemption. The Series A
2022 Bond was 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 was secured by a first lien on substantially all of Chugach's
assets. The Indenture prohibited outstanding short-term indebtedness
(other than trade payables) in excess of 15% of Chugach's net utility
plant and limited certain cash investments to specific securities.
(6) Debt (continued)
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 corresponding debt.
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.
On January 14, 2002, Chugach entered into an 18-day rate lock agreement
with JP Morgan on the 2002 refinancing. Chugach terminated the rate lock
on February 1, 2002, which generated a payment to Chugach of $1.2
million. The settlement payments were accounted for as regulatory assets
and amortized over the life of the corresponding debt, which was
authorized by the RCA in Order U-01-108(26). As of December 31, 2001,
the aggregate principal amount of the Series A Bond due 2022 was
$149,310,000. That principal amount was refinanced by the 2002 Series A
and Series B Bonds in February 2002.
(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:
2002 2001
---- ----
Carrying Fair Carrying Fair
Value Value Value Value
Long-term obligations
(including current installments) $395,000 $425,279 $374,720 $390,320
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). Chugach makes annual contributions
to the plans equal to the amounts accrued for pension expense. For the
union plans, Chugach pays a contractual hourly amount per union employee,
which is based on total plan costs for all employees of all employers
participating in the plan. In these master, multiple-employer plans, the
accumulated benefits and plan assets are not determined or allocated
separately to the individual employer. Costs for union plans were
approximately $2,253,000 in 2002, $1,990,000 in 2001 and $2,017,000 in
2000. In 2002, 2001 and 2000, Chugach contributed $1,401,000, $1,397,000
and $1,057,000, respectively, to the NRECA plan.
(9) Deferred Charges
Deferred charges, net of amortization, consisted of the following at
December 31:
2002 2001
---- ----
Debt issuance and reacquisition costs $14,155,863 $15,649,174
Refurbishment of transmission equipment 234,568 243,828
Computer software and conversion 5,666,620 8,161,890
Studies 1,952,074 1,776,576
Business venture studies 601,217 531,416
Fuel supply negotiations 329,901 348,986
Major overhaul of steam generating unit 2,701,076 17,092
Environmental matters and other 154,205 272,899
Other regulatory deferred charges 2,194,077 1,704,432
--------- ---------
$27,989,601 $28,706,293
=========== ===========
(10) Employee Representation
Approximately 72% of Chugach's employees are represented by the
International Brotherhood of Electrical Workers (IBEW). The various IBEW
contracts expire on June 30, 2006.
(11) Deferred Credits
Deferred credits at December 31 consisted of the following:
2002 2001
---- ----
Regulatory liability - unamortized gain on
reacquired debt $0 $15,629,104
Refundable consumer advances for construction 2,817,614 2,163,944
Estimated initial installation costs for
transformers and meters 364,766 447,378
Post retirement benefit obligation 405,700 405,700
New business venture 30,256 30,256
Other 595,252 771,409
------- -------
$4,213,588 $19,447,791
========== ===========
In conjunction with the 1991 refinancing described in note 6, Chugach had
recognized a gain of approximately $45,000,000. The Alaska Public
Utilities Commission (APUC), required Chugach 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 $188,082 of the deferred gain was amortized in 2002 prior
to the 2002 refinancing. The balance of the gain was extinguished with
the transactions associated with the 2002 refinancing. Approximately
$1,231,000 of the deferred gain was amortized in 2001. Approximately
$1,553,000 of the deferred gain was amortized in 2000.
(12) Bradley Lake Hydroelectric Project
Chugach 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. Chugach 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
(12) Bradley Lake Hydroelectric Project (continued)
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. Chugach has a 30.4% share of the project's capacity. The
share of debt service exclusive of interest, for which Chugach has
guaranteed, is approximately $44,000,000. Under a worst-case scenario,
Chugach could be faced with annual expenditures of approximately $4.1
million as a result of Chugach's 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 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, 2002 (the most recent date for which information is available).
Chugach's share of expenses was $4,343,562 in 2002, $3,929,614 in 2001
and $3,696,829 in 2000 and is included in purchased power in the
accompanying financial statements.
(In thousands) Total Proportionate Share
----- -------------------
Plant in service $ 307,016 $ 93,333
Accumulated depreciation (74,503) (22,649)
Interest expense 9,235 2,807
Other electric plant in service represents Chugach's share of a Bradley
Lake transmission line financed internally and Chugach's share of the
Eklutna Hydroelectric Project, purchased in 1997 (note 13).
(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, including their corresponding
interest in the project, consists of Chugach (30%), MEA (16.7%) and AML&P
(53.3%).
Other electric plant in service includes $1,957,742 representing
Chugach'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
Chugach is a participant in various legal actions, rate disputes,
personnel matters and claims both for and against Chugach's interests.
Management believes the outcome of any such matters, other than the final
outcome of Order U-01-108(26) described in note (17) "Subsequent
Events-Regulation," will not materially impact Chugach's financial
condition, results of operations or liquidity.
Long-Term Fuel Supply Contracts
Chugach 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
Chugach is the principal supplier of power under long-term wholesale
power contracts with MEA and HEA. These contracts represented $58.7
million or 34.1% of operating revenues in 2002, $57.7 million or 32.3% in
2001 and $45.2 million or 28.5% in 2000. These contracts will expire in
2014.
(14) Commitments and Contingencies (continued)
Cooper Lake Hydroelectric Plant
Chugach discovered polychlorinated biphenyls (PCBs) in paint, caulk and
grease at the Cooper Lake Hydroelectric plant during initial phases of a
turbine overhaul. A 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 state and federal agencies and
approved by FERC. In 2000, Chugach sampled sediments and fish collected
from Kenai Lake and other waters. While low levels of PCBs were found in
some sediment samples taken near the plant, no pathway from sediment to
fish was established. While the levels of PCBs in fish from Kenai Lake
were similar to levels found in fish from other lakes within the region,
Chugach conducted additional sampling and analysis of fish in Kenai Lake
and other waters and filed Chugach's final report dated April 1, 2002
with FERC, which analyzed the results of the sampling. Based on these
analyses, Chugach concluded that no further PCB sampling and analysis in
Kenai Lake was necessary. In a letter dated June 13, 2002, FERC informed
Chugach that its review of the report supported Chugach's conclusions and
agreed Chugach was not required to conduct further PCB sampling and
analysis in Kenai Lake. In its recent order in Chugach's general rate
case, Order U-01-108(26), the RCA permitted the costs associated with the
overhaul and the PCB remediation to be recovered through rates.
Consequently, management believes the costs of the PCB remediation and
studies will have no material impact on Chugach's financial condition or
results of operations. Chugach will be filing a request in 2003 with the
RCA to allow Chugach to record the costs Chugach incurred to investigate
the presence of PCBs in Kenai Lake to be recovered through rates.
Legal Proceedings
Matanuska Electric Association, Inc., v. Chugach Electric Association,
Inc., Superior Court Case No. 3AN-99-8152 Civil
This action is 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 Chugach's sale of power to MEA
during that time. MEA asserted Chugach breached that contract by failing
to provide information, by failing to properly manage Chugach's long-term
debt, and by failing to bring Chugach's base rate action to a Joint
Committee before presenting it to the RCA. The committee is defined in
the power sales contract and consists of one MEA and two Chugach board
members. All of MEA's
(14) Commitments and Contingencies (continued)
claims have been dismissed. On April 29, 2002, MEA appealed the Superior
Court's decisions relating to Chugach's financial management and
Chugach's failure to bring Chugach's base rate action to the joint
committee before filing with the RCA to the Alaska Supreme Court. Chugach
cross-appealed the Superior Court's decision not to dismiss the financial
management claim on jurisdictional and res judicata grounds. Oral
argument has been set by the Supreme Court for April 15, 2003. Management
is uncertain as to the outcome but will vigorously defend the appeal.
Chugach has certain additional litigation matters and pending claims that
arise in the ordinary course of Chugach's business. In the opinion of
management, no individual matter or the matters in the aggregate is
likely to have a material adverse effect on Chugach's results of
operations, financial condition or liquidity.
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 governing regulatory commission, which was
the APUC in 1992 and is currently the RCA. The tax is assessed on all
retail consumers and is based on kilowatt-hour (kWh) consumption. The
Regulatory Cost Charge has decreased since its inception (November 1992)
from an initial rate of $.000626 per kWh to the current rate of $.000318,
effective October 1, 2002.
(15) Segment Reporting
Chugach 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 derived its revenues from provision of residential
and commercial internet services and products. The reporting segments
follow the same accounting policies used for Chugach'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 Chugach, which are patterned upon usage. As of
March 6, 2001, with an effective date of March 20, 2001, Chugach sold the
bulk of Chugach'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. The following is a
tabulation of business segment information for the years ended December
31:
2002 2001 2000
---- ---- ----
Operating Revenues
Internet $0 $196,051 $1,170,448
Energy 171,944,918 178,399,163 157,370,666
----------- ----------- -----------
Total operating revenues 171,944,918 178,595,214 158,541,114
=========== =========== ===========
Assignable Margins
Internet 0 (165,273) (1,505,518)
Energy (2,016,150) 5,704,409 11,185,296
----------- --------- ----------
Total assignable margins (2,016,150) 5,539,136 9,679,778
=========== ========= =========
Assets
Internet 0 0 550,275
Energy 570,214,874 575,281,187 539,195,705
----------- ----------- -----------
Total assets 570,214,874 575,281,187 539,745,980
=========== =========== ===========
Capital Expenditures
Internet 0 0 163,565
Energy 16,417,119 36,408,253 46,566,478
---------- ---------- ----------
Total capital expenditures 16,417,119 36,408,253 46,730,043
========== ========== ==========
(16) Quarterly Results of Operations (unaudited)
2002 Quarter Ended
Dec. 31* Sept. 30 June 30 March 31
-------- -------- ------- --------
Operating Revenue $39,015,326 $41,523,323 $42,837,727 $48,568,542
Operating Expense 39,742,069 35,548,872 36,589,007 37,489,988
Net Interest 6,013,016 5,994,890 6,039,051 7,995,786
--------- --------- --------- ---------
Net Operating Margins (6,739,759) (20,439) 209,669 3,082,768
Non-Operating Margins 735,253 94,646 122,622 499,090
------- ------ ------- -------
Assignable Margins (6,004,506) $74,207 $332,291 $3,581,858
=========== ======= ======== ==========
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
========== ======= ========== ==========
*The reduction to operating revenue described in note 17 "Subsequent
Events - Regulation" was recorded in the 2002 quarter ended December 31.
(17) Subsequent Events
Refinancing
The indenture initially governing the outstanding bonds of Chugach, 2001
Series A, 2002 Series A and 2002 Series B, provided that the bonds were
secured by a mortgage on substantially all of Chugach's assets so long as
any amounts remained outstanding to CoBank on bonds issued under the
indenture. Upon the retirement of the bonds issued to CoBank, Chugach's
outstanding bonds became subject to an Amended and Restated Indenture
pursuant to which the bonds became unsecured obligations of Chugach.
(17) Subsequent Events (continued)
Chugach and CoBank have entered into a Master Loan Agreement dated as of
December 27, 2002, pursuant to which CoBank and Chugach replaced the
bonds issued to CoBank with unsecured promissory notes not governed by
the indenture. CoBank returned the old CoBank bonds to Chugach on January
22, 2003. Accordingly, under the terms of the Amended and Restated
Indenture, all of Chugach's outstanding bonds became unsecured
obligations of Chugach as of January 22, 2003.
Regulation
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. Chugach 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 interim rate increase was based on a
normalized (adjusted for recurring expenses) test year and a system
ratemaking Times Interest Earned Ratio (TIER) of 1.35. In this filing for
permanent rates, Chugach proposed that margins be calculated using a rate
base/rate of return methodology rather than the TIER methodology
previously used.
As anticipated in Chugach's July 2001 original filing, on April 15, 2002,
Chugach submitted a filing with the RCA to update certain known and
measurable costs and savings that had occurred outside the 2000 Test
Year. In the updated filing, Chugach reduced its base rate increase
request from 6.5% to 5.7%, or approximately $0.9 million in the revenue
requirement on a system basis. The revised filing also reflected an
increase in depreciation expense of approximately $1.5 million due to the
completion of the Beluga Unit 7 re-powering project and a reduction in
annualized interest expense, due to Chugach's recent refinancing efforts,
of $2.4 million. In this revised filing, Chugach continued to request
$11.9 million in margins. As a result of reduced interest costs, this
would yield an equivalent system TIER of 1.47.
Three intervenors filed pre-filed testimony with the RCA in July 2002
opposing various aspects of Chugach's proposal. Chugach filed its reply
testimony with the RCA on October 1, 2002. The hearing to resolve the
outstanding issues associated with the 2000 test year rate case took
place in November and December of 2002, concluding on December 13, 2002.
On February 6, 2003, Chugach received Order U-01-108(26) from the RCA,
which among other things included the following.
(17) Subsequent Events (continued)
Chugach will be required to use TIER in calculating return levels.
Chugach's system overall TIER was revised downward from 1.35 to 1.30, a
difference that would reduce margins by approximately $1.3 million based
on the 2000 test year and that would also have similar impacts in
subsequent years.
Chugach will be required to treat AFUDC/IDC as a reduction to long-term
interest expense, which reduces the revenue requirement by approximately
$1.2 million.
The RCA reduced Chugach's normalized interest rate of 3.8% to 2%, which
equates to a revenue requirement reduction of approximately $1.1 million.
Chugach's overall Depreciation Study was approved, although the RCA did
require approximately $0.7 million in downward adjustments, which will
not affect margins in future years.
There are several outstanding questions regarding interpretation of the
Order that have not yet been clarified. However, based upon our analysis,
the Order would require a refund of revenues collected in 2001 of
approximately $1.1 million of revenues collected in 2002 of approximately
$6.0 million, which amounts were recorded as a reduction to operating
revenues in 2002. The ultimate amount, which may be refunded, may change
based upon RCA's reconsideration of the Order and Chugach cannot predict
the outcome of reconsideration of the issues inherent in the Order.
The Order would also require a reduction in estimated 2003 revenues of
approximately $6.0 million. Chugach has calculated, that based on the
budgeted revenues and expenditures, under Order 26, Chugach may have
insufficient margins to yield margins for interest equal to at least a
1.10 in 2003.
The CoBank Master Loan Agreement requires Chugach to establish and
collect rates reasonably expected to yield margins for interest equal to
at least 1.10 times interest expense. CoBank waived the rate covenant as
of December 31, 2002, and reduced the rate covenant for 2003 from 1.10 to
1.08 if the RCA fails to modify the Order to set rates sufficient to
allow Chugach to generate margins for interest equal to at least 1.10
times interest charges. CoBank's prospective modification of the rate
covenant for 2003 is contingent upon Chugach promptly pursuing legal
action to force the RCA to modify the Order to allow Chugach to satisfy
the rate covenant as originally written in the CoBank loan agreement.
Chugach believes that it will achieve compliance with the covenant as
revised. The Amended and Restated Indenture also requires Chugach,
subject to any necessary regulatory approval, to establish and collect
rates reasonably expected to yield margins for interest equal to at least
1.10 times total interest expense. If there occurs any material change in
the circumstances contemplated at the time rates were most recently
reviewed, the Amended and Restated Indenture requires Chugach to seek
appropriate
(17) Subsequent Events (continued)
adjustments to those rates so that they would generate revenues
reasonable expected to yield margins for interest equal to at least 1.10
times interest charges, subject to any necessary regulatory approval or
determination.
In order to maintain Chugach's compliance with these covenants, Chugach
is taking the actions described below.
On February 13, 2003, Chugach filed a Motion with the RCA asking the RCA
to stay the effect of its Order until after the RCA considers Chugach's
Petition for Reconsideration of Order 26.
On February 18, 2003, the RCA granted, in part, Chugach's motion for
stay. Specifically, the RCA stayed, until further order of the RCA,
Ordering Paragraph 1 of Order U-01-108(26) which states, "Chugach's rates
will be established on the basis of the 2000 test year revenue
requirement recomputed in accordance with our decisions set out in the
body of this Order." The RCA stayed the two Ordering paragraphs of the
Order that would have required Chugach to put the new rates into effect.
The RCA also allowed a one-week extension until February 28, 2003, to
comply with ordering paragraphs 2 and 3, which require Chugach to
recalculate its revenue requirement and cost-of-service studies
reflecting the impact of Order U-01-108(26) on Chugach's rates. The RCA
also extended the time to file Petitions for Reconsideration of Order
U-01-108(26) one week to February 28, 2003. Chugach filed the Petition
for Reconsideration with the RCA on February 28, 2003. The Public
Advocacy Section (PAS), also filed a Petition for Reconsideration that,
in part, seeks to remove, from depreciation expense that the RCA allowed,
certain depreciation associated with Beluga Units 6 and 7 because the
plant was added outside the 2000 Test Year upon which the rates were
based. The RCA issued an Order on March 4, 2003, extending the time for
filing responses to petitions for reconsideration from March 10 to March
14, 2003, and determined that the period for ruling on the petitions for
reconsideration should be extended from March 31 to April 15, 2003.
Management is uncertain as to the outcome but will vigorously defend its
position. Under Alaska law, Chugach's financial covenants in the Amended
and Restated Indenture are valid and enforceable, and rates set by the
RCA must be adequate to meet those covenants. If the RCA does not modify
the Order to allow Chugach to charge rates reasonably expected to yield
margins for interest equal to at least 1.10 times interest expense,
Chugach intends to bring action to enforce that provision of the Alaska
state law described above.
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
Chugach operates 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 the General Manager. The following table sets
forth certain information with respect to our executive officers and directors.
Name Age Position
Evan J. Griffith............................ 61 General Manager
Lee D. Thibert.............................. 47 Executive Manager, Power Delivery/Chief of
Staff
Michael R. Cunningham....................... 53 Chief Financial Officer
William R. Stewart.......................... 55 Executive Manager, Administration
Bradley W. Evans............................ 48 Executive Manager, Energy Supply
Bruce Davison............................... 54 President and Director
Dave Cottrell............................... 55 Vice President and Director
Christopher Birch........................... 52 Secretary and Director
Jeffrey W. Lipscomb......................... 52 Treasurer and Director
Samuel W. Cason............................. 43 Director
Patricia B. (Pat) Jasper.................... 73 Director
H. A. (Red) Boucher......................... 82 Director
Executive Officers
Evan J. Griffith was appointed General Manager on May 1, 2002. Prior to
that appointment he had served as Executive Manager, Finance and Energy Supply
since an internal reorganization on June 1, 1997. Prior to that, he was
Executive Manager, Finance & Planning from August 1989 to June 1997. Prior to
his Chugach employment, he was Budget/Program Analyst for the Anchorage
Municipal Assembly from August 1984 to August 1989.
Lee D. Thibert was appointed Executive Manager, Power Delivery/Chief of
Staff on June 3, 2002. Prior to that appointment he had served as Executive
Manager, Transmission & Distribution Network Services since the June 1, 1997
reorganization. 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.
William R. Stewart was appointed Executive Manager, Administration on
June 5, 2002. Prior to that appointment he had served as Executive Manager,
Retail Services since the June 1, 1997 reorganization. Prior to that, he was
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 at Chugach since 1969.
Michael R. Cunningham was appointed Chief Financial Officer on June 5,
2002. Prior to that appointment he had served as Controller since 1986. Prior to
that he was Budget Analyst and Manager of Accounting since beginning his Chugach
employment in 1982. Prior to his Chugach employment, Mr. Cunningham spent 15
years in various capacities with Pacific Northwest Bell Telephone Company.
Bradley W. Evans was appointed Executive Manager, Energy Supply on June
5, 2002. Prior to that appointment he had served as Director of Energy Supply
since February 26, 2001. Prior to his Chugach employment, Mr. Evans served as
Manager, System Dispatch for Golden Valley Electric Association.
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.
Dave Cottrell serves as Vice President of the Board. Mr. 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.
Red Boucher has served on the board since 1999. He has previously
served as Vice President. 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 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.
Sam Cason is a self-employed attorney. He was elected to a 3-year term
on the board in 2002.
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 five executive officers, each of whose total cash and
cash equivalent compensation exceeded $100,000 for 2002, and for all such
executive officers as a group:
Name Principal Position Year Salary Bonus Total
Evan J. Griffith General Manager 2002 $172,239 $0 $172,239
2001 142,884 7,770 150,654
2000 131,657 0 131,657
Lee D. Thibert Executive Manager, 2002 154,881 0 154,881
Power Delivery/Chief 2001 142,425 0 142,425
of Staff
2000 131,710 0 131,710
Michael R. Cunningham Chief Financial Officer 2002 130,220 0 130,220
2001 119,093 0 119,093
2000 112,727 0 112,727
William R. Stewart Executive Manager, 2002 159,839 0 159,839
Administration 2001 158,902 0 158,902
2000 134,398 0 134,398
Bradley W. Evans Executive Manager, 2002 128,227 0 128,227
Energy Supply 2001 96,472 0 96,472
2000 0 0 0
Chugach's 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.
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.
On October 16, 2002, the Board of Directors authorized an amendment to
the Plan with an effective date of November 1, 2002. Under the amended Plan, the
retirement benefit payable to any Participant whose retirement is postponed
beyond his or her Normal Retirement Date shall be computed as of the
Participant's actual retirement date. The retirement benefit payable to any
Participant under the 30-Year Plan shall be computed as of the first day of the
month in which the Participant's actual retirement date occurs.
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 35 40
-- -- -- -- -- --
$125,000 $37,500 $50,000 $62,500 $75,000 $87,500 $100,000
$150,000 $45,000 $60,000 $75,000 $90,000 $105,000 $120,000
$175,000 $52,500 $70,000 $87,500 $105,000 $122,500 $140,000
$200,000 $60,000 $80,000 $100,000 $120,000 $140,000 $160,000
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, 2002 taken into account under the
Plan for the executive officers is shown below. Base salary for 2002 taken into
account under the Plan for purposes of determining final average salary is also
included.
Name Principal Position Benefit Service Covered Compensation
Evan J. Griffith General Manager 12 years, 4 months $185,016
Lee D. Thibert Executive Manager, Power
Delivery/Chief of Staff 14 years, 7 months 143,813
Michael R. Cunningham Chief Financial Officer 19 years, 1 month 122,013
William R. Stewart* Executive Manager, Administration 2 months 142,147
Bradley W. Evans Executive Manager, Energy Supply 1 year, 10 months 130,000
* Under the Plan in effect prior to November 1, 2002, Mr. Stewart had 30 years
of service as of April 1, 2000, and was no longer eligible to receive
contributions on his behalf to the Plan. Under the terms of the amendment to the
Plan, approved by the Board of Directors on October 16, 2002, Mr. Stewart was
re-enrolled effective November 1, 2002.
Employment Arrangements
In May 2002, we entered into an employment agreement with Evan J.
Griffith, our General Manager. He is paid an annual base salary of $185,000.
Mr. Griffith also is eligible to receive additional compensation, bonus and
benefits for meeting performance goals established annually by the Board of
Directors.
Item 12 - Security Ownership of Certain Beneficial Owners and Management
Not Applicable
Item 13 - Certain Relationships and Related Transactions
Not Applicable
Item 14 - Disclosure Controls and Procedures
Evaluation of Controls and Procedures
We maintain a set of disclosure controls and procedures that are
designed to ensure that information required to be disclosed in our reports
filed under the Securities Exchange Act of 1934, as amended ("Exchange Act") is
recorded, processed, summarized and reported within the time periods specified
in the SEC's rules and forms. Within the 90 days prior to the date of this
report, we carried out an evaluation, under the supervision and with the
participation of our management, including our Principal Executive Officer
(General Manager) and our Chief Financial Officer (CFO), of the effectiveness of
the design and operation of our disclosure controls and procedures pursuant to
Rule 13a-14 of the Exchange Act. Based on that evaluation, our General Manager
and CFO concluded that Chugach's disclosure controls and procedures are
effective in timely alerting them to material information relating to Chugach's
requirement to be included in Chugach's Exchange Act filings. There were no
significant changes in Chugach's internal controls that could significantly
affects its disclosure controls and procedures since the date of the evaluation.
PART IV
Item 15 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
Page
Financial Statements
Included in Part IV of this Report:
Independent Auditors' Report 37
Balance Sheets, December 31, 2002 and 2001 38-39
Statements of Revenues, Expenses and Patronage Capital,
Years ended December 31, 2002, 2001 and 2000 40
Statements of Cash Flows,
Years ended December 31, 2002, 2001 and 2000 41
Notes to Financial Statements 42-68
Financial Statement Schedules
Included in Part IV of this Report:
Independent Auditors' Report 77
Schedule II - Valuation and Qualifying Accounts,
Years ended December 31, 2002, 2001 and 2000 78
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.
Independent Auditors' Report
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association,
Inc. as of December 31, 2002 and 2001, 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, 2002. In connection with our audits of the
financial statements, we have also audited the financial statement schedule
listed in Item 15 herein. These financial statements and financial statement
schedule are the responsibility of the Association's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standard generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Chugach Electric Association,
Inc. as of December 31, 2002 and 2001, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2002, in conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly, in all material respects, the information set forth
therein.
/s/ KPMG, LLP
Anchorage, Alaska
March 3, 2003
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, 2002 (318,757) (344,472) 349,684 (313,545)
December 31, 2001 (441,933) (116,881) 240,057 (318,757)
December 31, 2000 (389,223) (373,666) 320,956 (441,933)
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 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)
4.14 Form of 2002 Series A Bond due 2012. (14)
4.18 Form of 2002 Series B Bond due 2012. (14)
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)
10.44 Line of Credit Agreement and Promissory Note between the Registrant and the National Bank for
Cooperatives dated May 5, 1993. (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 dated April 18, 1994. (1)
10.44.3 Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives
dated May 1, 1995. (1)
10.44.4 Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives
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)
10.44.6 Master Loan Agreement between the Registrant and CoBank, ACB dated December 27, 2002
10.44.7 Promissory Note and Consolidating Term Loan Supplement between the Registrant and CoBank, ACB dated December
27, 2002.
10.47.1 Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance
Corporation dated October 15, 2002.
10.52 Employment Agreement between the Registrant and Evan J. Griffith dated effective May 1, 2002. (15)
12.1 Statement regarding computation of ratios. (14)
99.1 Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(1) Previously filed as an exhibit to 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.
(15) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated June 30, 2002.
REPORTS ON FORM 8-K
Reference is made to the April 30, 2002 8-K, which discussed the
appointment of Evan J. Griffith as Chugach's new General Manager.
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 28, 2003.
CHUGACH ELECTRIC ASSOCIATION, INC.
By: /s/ Evan J. Griffith
Evan J. Griffith, General Manager
Date: March 28, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below on March 28, 2003, by the following persons on behalf of
the registrant in the capacities indicated:
/s/ Evan J. Griffith
Evan J. Griffith General Manager
(Principal Executive Officer)
/s/ Lee D. Thibert
Lee D. Thibert Executive Manager, Power Delivery/Chief of Staff
/s/ Michael R. Cunningham
Michael R. Cunningham Chief Financial Officer
(Principal Financial Officer)
/s/ William R. Stewart
William R. Stewart Executive Manager, Administration
/s/ Bradley W. Evans
Bradley W. Evans Executive Manager, Energy Supply
/s/ Bruce Davison
Bruce Davison Director & President
/s/ Dave Cottrell
Dave Cottrell Director & Vice President
/s/ Christopher Birch
Christopher Birch Director & Secretary
/s/ Jeffrey Lipscomb
Jeffrey Lipscomb Director & Treasurer
/s/ Samuel W. Cason
Samuel W. Cason Director
/s/ Patricia B. Jasper
Patricia B. Jasper Director
/s/ H. A. Boucher
H. A. Boucher Director
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Evan J. Griffith, certify that:
1. I have reviewed this annual report on Form 10-K of Chugach Electric
Association, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report; 3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report; 4. The
registrant's other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:
a) Designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date; 5. The registrant's other certifying officer and I
have disclosed, based on our most recent evaluation, to the registrant's
auditors and the audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) Any fraud, whether or not material, that involves
management or other employees who have a significant role in the registrant's
internal controls; and 6. The registrant's other certifying officer and I have
indicated in this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003 /s/ Evan J. Griffith
----------------
Evan J. Griffith
General Manager and Principal
Executive Officer
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Michael R. Cunningham, certify that:
1. I have reviewed this annual report on Form 10-Q of Chugach Electric
Association, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report; 3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report; 4. The
registrant's other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:
a) Designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date; 5. The registrant's other certifying officer and I
have disclosed, based on our most recent evaluation, to the registrant's
auditors and the audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) Any fraud, whether or not material, that involves
management or other employees who have a significant role in the registrant's
internal controls; and 6. The registrant's other certifying officer and I have
indicated in this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003 /s/ Michael R. Cunningham
---------------------
Michael R. Cunningham
Chief Financial Officer and
Principal Financial Officer
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 2002 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.