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, 2004
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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 Electron 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:
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(Title of class)
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(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.
2004 Form 10-K Annual Report
Table of Contents
PART I Page
Item 1 - Business 1
Item 2 - Properties 8
Item 3 - Legal Proceedings 16
Item 4 - Submission of Matters to a Vote of Security Holders 17
PART II
Item 5 - Market for Registrant's Common Equity and Related
Stockholder Matters 17
Item 6 - Selected Financial Data 18
Item 7 - Management's Discussion and Analysis of Financial Condition 19
and Results of Operations
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 65
Item 9A - Disclosure Controls and Procedures 65
Item 9B - Other Items 65
PART III
Item 10 - Directors and Executive Officers of the Registrant 66
Item 11 - Executive Compensation 69
Item 12 - Security Ownership of Certain Beneficial Owners and
Management 72
Item 13 - Certain Relationships and Related Transactions 72
Item 14 - Principal Accountant Fees and Services 72
PART IV
Item 15 - Exhibits and Financial Statement Schedules 73
SIGNATURES 86
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 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.
Chugach makes its current and periodic reports available, free of
charge, on its 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 is the largest electric utility in Alaska. We are engaged in
the generation, transmission and distribution of electricity to approximately
75,500 active 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.
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 $.000397 per kWh of retail electricity sold. This charge is assessed to fund
the operations of the Regulatory Commission of Alaska (RCA). It is a
pass-through and thus does not impact our margins.
Our workforce consists of approximately 355 full-time employees.
Approximately two-thirds of our employees are members of the International
Brotherhood of Electrical Workers (IBEW). We have three collective bargaining
agreements with the IBEW that are in effect through June 30, 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.
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 approximately 30,000 meters.
Our members are the consumers of the electricity sold by us. As of
December 31, 2004, we had 62,684 retail members receiving service at
approximately 75,500 active 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 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 in any year
and such excess is designated on our Statements of Revenues, Expenses and
Patronage Capital as "assignable margins." Retained assignable margins are
designated on our balance sheet as "patronage capital" that is assigned to each
member on the basis of patronage.
We have 530 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 84% (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 2004, approximately 86% of our energy was generated at the Beluga
facility. The Bradley Lake Hydroelectric Project provides up to 27.4 megawatts
for our retail customers and up to 38.6 megawatts for our wholesale customers.
We also purchase approximately 40 megawatts from the Nikiski power plant on the
Kenai Peninsula. We operate 1,645 miles of distribution line and 402 miles of
transmission line. For the year ended December 31, 2004, we sold 2.6 billion
kilowatt hours (kWh) of electrical power.
Customer Revenue From Sales
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, 2004:
Percent of Revenue
MWh 2004 Revenues from Sales
Direct retail sales:
Residential.................... 571,320 $65,651,405 33%
Commercial..................... 653,729 59,085,360 30%
------- ---------- ---
Total.......................... 1,225,049 124,736,765 63%
Wholesale sales:
MEA............................ 658,208 37,164,894 19%
HEA............................ 477,256 24,790,344 12%
Seward......................... 62,176 2,850,001 1%
------ --------- --
Total.......................... 1,197,640 64,805,239 32%
Economy energy sales(1) ............ 206,835 8,867,625 5%
------- ---------
Total revenue from sales............ 2,629,524 198,409,629 100%
========= ====
Miscellaneous energy revenue 2,836,986
---------
Total energy revenues $201,246,615
============
(1) Economy sales were made to Golden Valley Electric Association (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 the Glenn Highway on the north.
Customers
As of December 31, 2004, we had 62,684 members being served by
approximately 74,750 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 2004, our wholesale power contracts,
including the fuel component, produced $64.8 million in revenues, representing
32% of our total revenues and 46% of our total sales to customers.
MEA and HEA
We have two power sales contracts with Alaska Electric Generation &
Transmission Cooperative, Inc., (AEG&T): one for 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 sold power to AEG&T, for resale to MEA and
HEA. On June 19, 2002, the RCA approved the request by Alaska Electric and
Energy Cooperative, Inc. (AEEC) and AEG&T to Transfer Certificate of Public
Convenience and Necessity No. 345 to serve as the power supplier of HEA to AEEC,
instead of AEG&T. HEA is the sole member of AEEC. As part of this transaction
our power sales agreement was assigned to AEEC and the Nikiski dispatch
agreement was assigned to HEA with certain exceptions with the remaining rights
and obligations under the Dispatch Agreement being assigned to AEEC. Management
has not experienced a decline in revenue as a result of this transfer. Under our
contracts, each of MEA and HEA is obligated to pay us for the power sold to
AEG&T and AEEC even if AEG&T and AEEC do not pay.
Under the contract with AEG&T and MEA, MEA is obligated to purchase all
of its electric power and energy requirements from us. 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 after 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. Chugach and MEA met on October
27, 2004, pursuant to Section 12(c) of the MEA/Chugach Power Sales Agreement.
This provision requires the parties to meet no later than ten years prior to the
termination date of the Agreement, to discuss a possible renewal, extension, or
modification of the Agreement, as well as the desires and potential
circumstances of all parties following the termination date. At that meeting and
shortly thereafter by letter dated November 2, 2004, MEA communicated to Chugach
that MEA does not desire to renew, extend or modify the Agreement. Further, MEA
stated that it does not envision any type of firm power purchase arrangement
with Chugach following expiration of the Agreement on December 31, 2014. MEA
assured Chugach that it intends to continue to purchase power from Chugach in
accordance with the Agreement through December 31, 2014.
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 AEEC) to
take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per
year. The HEA contract, as interpreted by the Alaska Public Utilities Commission
(APUC), limits the costs that may be included in our rates charged to HEA. The
HEA contract expires on January 1, 2014. HEA's remaining resource requirements
are provided by AEEC's Nikiski cogeneration facility and AEEC's contract rights
to receive 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 AEEC 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.
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, not to exceed
seventy-two cumulative hours annually and thereby reduces the demand charge by
1/3 (approximately $350,000 annually). This agreement expires January 31, 2006.
Economy Customers
Since 1988, we have sold economy (nonfirm) energy to 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 have been 206,451 MWh, 191,616 MWh and
125,462 MWh for the years 2004, 2003 and 2002, respectively. No seller enjoys a
contractual priority in making such sales. GVEA makes purchases from the seller
offering the lowest competitive price.
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. 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 retail and wholesale
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 total interest expense. On February 6, 2003, we received Order
U-01-108(26) from the RCA, based on our 2000 test year general rate case, that
revised our overall TIER from 1.35 to 1.30. For the year ended December 31,
2004, our achieved TIER was calculated to be 1.35.
Our Service Areas and Local Economy
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. Agrium, a producer and marketer of agricultural nutrients and
industrial products, located on the Kenai Peninsula, may cease operations due to
a reduction in the supply of natural gas. If Agrium is unable to obtain
favorably-priced additional natural gas, Agrium may be forced to cease
production at the Kenai facility. This loss could have a negative affect on the
economy of the Kenai Peninsula. 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.
Load Forecasts
The following table sets forth our projected load forecasts for the
next five years:
Load (MWh) 2005 2006 2007 2008 2009
---------- ---- ---- ---- ---- ----
Retail............ 1,237,661 1,273,895 1,289,163 1,308,717 1,308,060
Wholesale......... 1,219,048 1,254,746 1,282,758 1,275,670 1,295,137
Economy........... 188,756 165,000 165,000 165,000 100,000
Losses............ 139,355 143,271 144,921 147,034 146,963
Total.......... 2,784,820 2,836,912 2,881,842 2,896,421 2,850,160
========= ========= ========= ========= =========
Sales are expected to increase over the next five years principally due
to economic growth resulting from increased federal and state spending. Our
total energy requirements are expected to grow at an average annual compounded
rate of 1.5% from 2005 to 2009, retail sales at a rate of 1.4% and wholesale
sales at a rate of 1.5%. 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 530 megawatts of installed capacity consisting of 17 generating
units at five power plants. These include 385.0 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
IGT in Anchorage; and 19.2 megawatts at the Cooper Lake facility, which is also
on the Kenai Peninsula. We also own rights to 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 IGT. 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. We are in the process of reviewing the lease. We have no reason
to believe that we will not be able to renew the lease if desired. The Cooper
Lake Hydroelectric Project is partially located on federal land. Consequently,
we must operate the Project pursuant to a major project license granted to us by
the Federal Energy Regulatory Commission (FERC) in May 1957. The current license
expires in 2007, so we are preparing an application for a new license for
continued operation of the project in consultation with state and federal
agencies, non-governmental organizations and interested public. We anticipate
that the FERC will conduct its relicensing process in a manner that allows us to
continue operation of the Project after 2007.
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 345.8 MW 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 combustion inspections performed in 2004
and 2003. Beluga Unit 5 also had combustion inspections in 2004 and 2003. Beluga
Unit 6 had a combustion inspection performed in 2004. Its first major inspection
since the unit was repowered in 2000 was performed in 2003. Its first major
inspection after the unit was repowered in 2001 was performed on Beluga Unit 7
in 2004. A combustion inspection was performed on Unit 7 during 2003. Beluga
Unit 8, a steam turbine, received routine annual inspections in 2004 and 2003.
The following matrix depicts nomenclature, run hours for 2004 and
percentages of contribution and other historical information for all Chugach
generation units.
Percent of
Commercial Operation Rating Run Hours Percent of Time
Facility Date Nomenclature (MW)(1) (2004) Total Run Hours Available
-------- ---- ------------ ------- ------ --------------- ---------
Beluga Power
Plant (3)
1 1968 GE Frame 5 19.6 556.7 1.04 90.4
2 1968 GE Frame 5 19.6 542.2 1.01 92.7
3 1972 GE Frame 7 64.8 6,692.5 12.49 94.8
5 1975 GE Frame 7 68.7 5,341.6 9.97 83.4
6 1975 AP 11DM-EV 79.2 8,176.4 15.26 93.1
7 1978 AP 11DM-EV 80.1 6,694.9 12.50 76.3
8 1981 BBC DK021150(2) 53.0 7,826.3 14.61 89.1
---------------
---------------
Bernice Lake 385.0
Power Plant
2 1971 GE Frame 5 19.0 4.4 0.01 99.82
3 1978 GE Frame 5 26.0 620.0 1.16 95.90
4 1981 GE Frame 5 22.5 1,194.4 2.23 96.21
---------------
---------------
Cooper Lake 67.5
Hydroelectric
Plant
1 1960 BBC MV 230/10 9.6 7,379.4 13.78 87.16
2 1960 BBC MV 230/10 9.6 8,086.4 15.09 94.24
---------------
---------------
IGT Power Plant 19.2
1 1964 GE Frame 5 14.1 187.8 0.35 97.18
2 1965 GE Frame 5 14.1 267.3 0.50 95.12
3 1969 Westinghouse 191G 18.5 79.6 0.15 99.30
--------------
46.7
Eklutna
Hydroelectric
Plant (4)
1 1955 Newport News 5.8 N/A(5) N/A(5) N/A5
2 1955 Oerlikon custom 5.9 N/A(5) N/A(5) N/A5
---------------
---------------
11.7(6)
System Total -------------- 53,570.3 100.00
530.10
===============
(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.
(6) Represents Chugach's 30% share, 11.7 MW maximum
Note: GE = General Electric, BBC = Brown Boveri Corporation, AP = Alstom Power
Transmission and Distribution Assets
As of December 31, 2004, our transmission and distribution assets
included 39 substations and 402 miles of transmission lines, 926 miles of
overhead distribution lines and 719 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 subject to 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 via easements and 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 30.4% (27.4 megawatts as currently
operated) 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. We are obligated to pay 30.4% of the annual project costs regardless
of project output.
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 and AEEC), 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). By
contract, we also provide transmission and related services to 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. The agreement may
be renewed for successive forty-year periods or for the useful life of the
project, whichever is shorter. We believe that our maximum annual liability for
our take-or-pay obligations is approximately $4.7 million. We believe that so
long as this project produces power taken by us for our use that this expense
will be recoverable through the fuel surcharge mechanism. The share of Bradley
Lake indebtedness for which we are responsible is approximately $41 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 of the defaulting
participant to pay its share, provided that no participant's percentage share is
increased by more than 25%.
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 2004, 86% of our power was generated from gas, and 86% 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, ChevronTexaco) and Marathon.
ConocoPhillips, AML&P and ChevronTexaco each own one-third of the gas produced
from the Beluga River Field and in 2004 provided approximately equal shares of
the Beluga gas. We have approximately 285 billion cubic feet (BCF) of remaining
gas committed to us from Marathon and the Beluga River Field producers
(including Period 3 gas). We currently use approximately 25 BCF of natural gas
per year for firm service. We estimate that our contract gas will last 7 to 12
years. Under almost all circumstances the deliverability supplied under our
contracts is sufficient to meet all the needs of the Beluga Plant.
Beluga River Field Producers
We have similar requirements contracts with each of ConocoPhillips,
AML&P and ChevronTexaco 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) ($2.6414
per thousand cubic feet (MCF) on January 1, 2005), plus taxes. The price during
this period under the ChevronTexaco contract is approximately 110% of the price
of gas under the Marathon contract (described below) ($3.3017 per MCF on January
1, 2005), 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. ConocoPhillips
has verbally indicated that it intends to terminate their supplemental gas
contract. Chugach will explore ways to cover these needs in the future.
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-2010. 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 closing prices of
New York Mercantile Exchange (NYMEX) Light, Sweet Crude Oil Futures, the
Producer Price Index for natural gas, and the Consumer Price Index for heating
fuel oil. The price on January 1, 2005, exclusive of taxes, was $3.0016 per MCF.
Under the terms of the Marathon contract, Marathon generally provides
the gas required for sales to GVEA, all of our requirements at Bernice Lake,
International and Nikiski and 40% of the requirements at Beluga, not related to
sales to GVEA. Marathon also has a right of first refusal to provide additional
gas under any sales agreements that we may enter into with electric utilities we
do not currently serve. The terms of the Marathon contract also gave Marathon a
right to provide additional volumes in the period following depletion of the
initial commitment of 215 BCF. On June 13, 2001, we were notified that Marathon
will not commit to supply any additional volumes.
ENSTAR
We entered into a transportation agreement with ENSTAR Natural Gas
Company (ENSTAR) in December 1992, whereby ENSTAR would transport our gas
purchased from the Beluga River Field producers or Marathon on a firm basis to
our International Power Plant at a transportation rate of $0.63 per MCF. In
addition, ENSTAR agreed to transport gas on an interruptible basis for
off-system sales at a rate of $0.29 per MCF. The agreement contains a minimum
monthly bill of $2,600 for firm service. ENSTAR has initiated a process to
provide transport services to Chugach, as well as other large users pursuant to
price terms and conditions set out in a tariff. We do not expect that will
result in price, terms and conditions unilaterally different from those in the
contract.
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 in 2000. A FERC approved plan, prepared in consultation with the
Environmental Protection Agency (EPA), was implemented to remediate the PCBs in
the plant. Chugach filed its final report with FERC in April of 2002 concluding
that no further analysis was necessary and in a letter dated June of 2002, FERC
agreed. In an 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. The costs of PCB sampling and analysis in Kenai Lake
were accounted for as an expense.
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 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.
All of MEA's claims were dismissed by the Superior Court. 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. We
cross-appealed the Superior Court's decision not to dismiss the financial
management claim on jurisdictional and res judicata grounds.
The Alaska Supreme Court, on October 8, 2004, ruled in Chugach's favor
supporting its right under the power sales agreement to file for interim rate
relief without first going to the Joint Committee. The Supreme Court ruled
against Chugach in its cross appeal. The Supreme Court also overturned the
Superior Court's decision that dismissed MEA's claim asking for review of
Chugach's management of use of rate locks instead of defeasing debt based on the
Prudent Utility Practice standard under our power sales agreement. The Supreme
Court remanded this issue to the Superior Court.
On January 24, 2005, Chugach filed a summary judgment motion based on
Chugach's claim that in the 2000 Test Year rate case the RCA has already decided
the underlying issues relating to the prudency of Chugach's use of rate locks
instead of defeasing debt. This motion is pending. Management is uncertain of
the outcome of the proceeding before the Superior Court.
Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc.
Superior Court Case No. 3AN-04-11776 Civil
On October 12, 2004, MEA filed suit in Superior Court alleging a breach
of the power sales agreement between the parties and violation of Chugach's
bylaws in connection with allocation of margins (capital credits) to MEA for the
years 1998 through 2003. Allocation of capital credits assigns a share of the
margins earned in a particular year to each customer. Capital credits are
repatriated to customers at the discretion of the board of directors typically
many years after the margins are earned.
The suit seeks a declaration by the Court that Chugach is in breach of
its bylaws and the power sales agreement based on its allocation of capital
credits to MEA as well as injunctive relief requiring Chugach to calculate MEA's
capital credit allocations based on MEA's patronage and in accordance with
generally accepted accounting practices for nonprofit cooperatives and
cooperative principles. The suit also seeks damages in an unspecified amount to
compensate MEA for the alleged breach of contract.
Management intends to vigorously defend against the claim. Management
is uncertain of the outcome of the suit.
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 2004 2003 2002 2001 2000
---- ---- ---- ---- ----
Plant, net:
In service $442,552,526 $453,706,406 $450,480,385 $452,964,686 $427,127,258
Construction work in
Progress 25,278,388 16,560,438 20,224,302 28,887,008 42,027,617
---------- ---------- ---------- ---------- ----------
Electric plant, net 467,830,914 470,266,844 470,704,687 481,851,694 469,154,875
Other assets 91,523,673 88,524,659 99,510,187 93,429,493 70,591,105
---------- ---------- ---------- ---------- ----------
Total assets $559,354,587 $558,791,503 $570,214,874 $575,281,187 $539,745,980
============ ============ ============ ============ ============
Capitalization:
Long-term debt 363,357,786 384,289,179 389,834,179 364,310,000 312,219,945
Equities and margins 138,998,799 134,216,122 127,477,895 131,808,706 128,815,340
----------- ----------- ----------- ----------- -----------
Total capitalization $502,356,585 $518,505,301 $517,312,074 $496,118,706 $441,035,285
============ ============ ============ ============ ============
Summary Operations Data
Operating revenues $201,246,615 $184,032,413 $171,944,918 $178,595,214 $158,541,114
Operating expenses 173,340,037 156,153,029 149,369,936 147,496,721 126,430,273
Interest expense 21,491,865 22,710,828 26,230,825 28,353,487 26,158,769
Amortization of gain on
refinancing 0 0 188,082 1,123,973 1,440,479
- - ------- --------- ---------
Net operating margins 6,414,713 5,168,556 (3,467,761) 3,868,979 7,392,551
Nonoperating margins 1,187,743 1,084,564 1,451,611 1,670,157 2,287,227
--------- --------- --------- --------- ---------
Assignable margins $7,602,456 $6,253,120 $(2,016,150) $5,539,136 $9,679,778
========== ========== ============ ========== ==========
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). Chugach's authorized TIER for rate-making purposes on a system basis
is 1.30, which was ordered by the RCA in Order U-01-108(26). Generally, it is
not possible to achieve the authorized TIER due to factors such as adjustments
to the revenue requirement that eliminate certain ongoing costs and increases in
the costs of operation that occur after the test year on which rates were based.
Accordingly, we manage our business with a view toward achieving a TIER of 1.20
or greater. We achieved TIERs for the past five years as follows:
Year TIER
---- ----
2004 1.35
2003 1.27
2002 0.92*
2001 1.20
2000 1.39
*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.
"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. In addition, a Regulatory Cost Charge (RCC) is assessed on each
retail customer invoice to fund Chugach's share of the RCA's budget. The RCC tax
is revised annually by the RCA.
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.
Docket U-01-108
Chugach filed a general rate case on July 10, 2001, based on the 2000
test year and subsequently implemented interim and refundable rate increases as
approved by the RCA. 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%. Three wholesale customers and the Public
Advocacy staff of the RCA participated in the rate case.
Order No. 26
On February 6, 2003, Chugach received Order U-01-108(26) (Order 26)
from the RCA.
Order 26 required a refund of revenues collected in 2001 of
approximately $1.1 million and revenues collected in 2002 of approximately $6.0
million, which resulted in a net operating loss of approximately $2 million in
2002. Under the Order, Chugach's financial performance for 2002 fell below the
1.10 level contained in the Rate Covenants in its currently effective indenture,
the Amended and Restated Indenture, the CoBank Master Loan Agreement and the
MBIA Insurance Corporation's (MBIA) Reimbursement and Indemnity Agreement. (See
"Item 1-Business-Rate Regulation and Rates.")
In accordance with the Rate Covenant in the Amended and Restated
Indenture, on February 13, 2003, Chugach filed a Motion with the RCA asking the
RCA to stay the effect of Order 26 until after the RCA considered Chugach's
Petition for Reconsideration. On February 18, 2003, the RCA granted, in part,
Chugach's motion for stay. Chugach filed the Petition for Reconsideration with
the RCA on February 28, 2003.
Order No. 30
On April 14, 2003, the RCA issued Order No. 30 in Docket U-01-108,
significantly revising its earlier ruling. On April 28, 2003 Chugach submitted a
revised revenue requirement and cost of service study in compliance with RCA
Order No. 30. This order increased Chugach's revenue requirement by $3.1 million
and adjusted the required refund from $7.1 million to $1.9 million.
Order No. 33
On August 26, 2003, the RCA issued Order No. 33 and accepted Chugach's
April 28, 2003, compliance filing subject to reducing long-term interest expense
by $1.2 million associated with Allowance For Funds Used During Construction /
Interest During Construction (AFUDC/IDC). In Order No. 33, the RCA re-reversed
its earlier decision regarding the treatment of AFUDC/IDC.
Order No. 36
Effective November 7, 2003, the RCA approved Chugach's compliance
filing and final rates in this docket. As a result, and in relation to
prior-approved permanent rates, Chugach's rates on a system basis increased 0.07
percent, or an increase of 3.5 percent to retail customers and a decrease of 7.9
percent to wholesale customers.
The results of the RCA's decision on final rates were implemented on
November 10, 2003.
Appeal of RCA Orders
Chugach filed a timely appeal of RCA Orders Nos. 26, 30 and 33 to the
Alaska Superior Court. In its Appellant's brief dated February 18, 2004, Chugach
asserted that the RCA's orders contained three errors:
o The split TIER decision unduly discriminates against retail
customers;
o Interest expense was allocated on the basis of plant
associated with Generation and Transmission (G&T) and
Distribution rather than on the basis of debt associated with
each function; and
o Chugach is entitled to include all of its interest expense in
rates and the RCA's offset for IDC was not justified because
nearly all of the plant that produced the IDC was in service
by the time the new rate went into effect.
The resolution of the first two issues would not have changed the total
amount Chugach could have recovered through rates. If Chugach had prevailed on
the last issue, it would have been authorized to recover approximately
$1,000,000 more each year in rates.
One of Chugach's wholesale customers, MEA, also appealed the RCA's
orders. In its Appellant's brief, MEA argued that the RCA's decision to
normalize Chugach's variable rate debt at 3.8 percent and to authorize the
corresponding interest expense constitutes error based on the historic rates
prevailing for Chugach's variable rate debt. If MEA had prevailed on its
argument, Chugach's authorized rates would have been reduced by approximately
$1,000,000 each year.
After oral argument on October 8, 2004, the Alaska Superior Court
upheld all decisions of the RCA. We decided not to appeal this decision.
Provision For Rate Refund
At December 31, 2002, Chugach recorded a provision for rate refund of
$7.1 million. On April 15, 2003, the RCA issued Order No. 30 in Docket U-01-108,
significantly revising its earlier ruling in which $5.2 million of that
provision was reversed. Between March and November of 2003, additional
provisions were recorded in the amount of $3.8 million reflecting RCA decisions
through Order No. 30, in addition to RCA orders that continued through the
period. In October and November of 2003, Chugach's wholesale customers were
refunded $5.0 million. Between March 19 and April 19, 2004, Chugach issued
refunds totaling $0.6 million to its Small General Service class for customer
bills rendered between January 31 and November 10, 2003.
Our base rate changes, excluding fuel surcharges, for retail and
wholesale classes for the years 2002 through 2004 were as follows:
Rate Class * 2004 2003 2002
---------- ---- ---- ----
Retail 0.00% 0.24% 0.00%
Wholesale:
HEA 0.00% (10.9%) 0.00%
MEA 0.00% (12.4%) 0.00%
SES 0.00% (9.9%) 0.00%
* Rate changes shown are based on percent changes as applied to demand
and energy rate levels.
Base rate changes in 2003 were associated with Chugach's 2000 test
period general rate case discussed above.
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 mechanism. 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.
Year ended December 31, 2004, compared to the years ended December 31,
2003, and 2002
Margins
Our margins for the years ended December 31 were as follows:
2004 2003 2002
---- ---- ----
Net Operating Margins $ 6,414,713 $ 5,168,556 $(3,467,761)
Nonoperating Margins $ 1,187,743 $ 1,084,564 $1,451,611
----------- ----------- ----------
Assignable Margins $ 7,602,456 $ 6,253,120 $(2,016,150)
=========== =========== ============
The increase in assignable margins in 2004 of $1.3 million, or 22%, was
due primarily to a decrease in interest expense caused by lower interest rates.
The increase in assignable margins in 2003 of $8.3 million, or 410%, was due in
part to the reversal of $5.2 million of the provision for rate refunds that was
recorded in 2002 and a decrease in interest expense caused by lower interest
rates.
Nonoperating margins include interest income, AFUDC, capital credits
and patronage capital allocations. Nonoperating margins increased in 2004 from
2003 by $103,179, or 10%, due primarily to an increase in interest income caused
by a higher than average cash balance during the year and higher interest rates.
Nonoperating margins decreased in 2003 from 2002 by $367,000, or 25%, due to
lower interest rates, as well as a decrease in allocations of patronage capital
from CoBank.
Revenues
Operating revenues include sales of electric energy to retail,
wholesale and economy energy customers and other miscellaneous revenues. In
2004, operating revenues were $17.2 million, or 9%, higher than in 2003 due to
increased sales and higher fuel costs recovered in revenue through the fuel
surcharge mechanism. In 2003, operating revenues were $12.1 million, or 7%,
higher than in 2002 due in part to increased sales and to a $5.2 million partial
reversal recorded in 2003 of a $7.1 million provision for rate refund recorded
in 2002 and an increase of $2.5 million in economy energy sales to GVEA. In
addition, fuel costs were higher in 2003 and recovered in revenue through the
fuel surcharge mechanism. The major components of our operating revenue for the
year ending December 31 were as follows:
2004 2003 2002
---- ---- ----
Retail $124,736,765 $115,717,488 $110,082,014
Wholesale
HEA 24,790,344 21,733,244 22,035,973
MEA 37,164,894 34,205,260 30,018,227
Seward 2,850,001 2,461,200 2,709,752
Economy energy 8,867,625 7,112,276 4,567,179
Other 2,836,986 2,802,945 2,531,773
--------- --------- ---------
Total revenue $201,246,615 $184,032,413 $171,944,918
============ ============ ============
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 2004, 2003, and 2002,
economy sales to GVEA constituted approximately 5.0%, 4.0%, and 2.7%,
respectively, of our sales revenues. The increase in economy sales in 2004 from
2003 was due to GVEA's higher fuel costs than Chugach's, which made it more
economical for GVEA to purchase power from Chugach rather than generate its own.
The increase in economy sales in 2003 from 2002 was due to GVEA's maintenance
schedule as well as higher fuel prices.
Expenses
The major components of our operating expenses for the years ended
December 31 were as follows:
2004 2003 2002
---- ---- ----
Fuel $64,113,474 $48,667,262 $46,822,943
Power production 15,070,486 13,961,565 13,500,103
Purchased power 20,579,992 18,244,921 18,750,936
Transmission 6,350,344 4,511,002 3,930,902
Distribution 11,451,931 10,866,251 10,869,335
Consumer accounts 5,308,353 5,589,788 5,594,572
Administrative, general and other 22,476,005 26,520,189 22,251,895
Depreciation 27,989,452 27,792,051 27,649,250
---------- ---------- ----------
Total operating expenses $173,340,037 $156,153,029 $149,369,936
============ ============ ============
Fuel
Fuel expense increased by $15.4 million, or 32%, in 2004 from 2003 due
to higher fuel prices as well as higher fuel volume purchases. Fuel expense did
not vary materially in 2003 from 2002.
Power Production
Power production expense increased by $1.1 million, or 8%, in 2004 from
2003 due, in part, to the method in which maintenance costs are recorded was
updated in 2004 to more accurately reflect the costs in the proper functional
area. The increase was also due to higher material and professional services
costs associated with scheduled maintenance and inspections on multiple units at
Beluga. In addition, labor costs in 2003 were unusually low as a result of
reduced overtime and hiring constraints. Power production expense did not vary
materially in 2003 from 2002.
Purchased Power
Purchased power costs increased by $2.3 million, or 12.8%, in 2004 from
2003 due to higher fuel costs and increased sales. Purchased power costs did not
vary materially in 2003 from 2002.
Transmission
Transmission expense increased by $1.8 million, or 41%, in 2004 from
2003 due to increased transmission substation maintenance being performed in
2004. In addition, the increase was also due to the aforementioned update to the
method used to record maintenance costs. Transmission expense increased in 2003
from 2002 by $580 thousand, or 15%, due to transmission substation maintenance
being performed in 2003 that had been deferred in 2002 as a result of not being
able to schedule the necessary outages to perform the maintenance. In addition,
transmission right-of-way clearing had been deferred in 2002 as a result of
permitting issues was also performed in 2003.
Distribution
Distribution expense increased $586 thousand, or 5%, in 2004 from 2003
due to the aforementioned update to the method used to record maintenance costs.
Distribution expense did not vary materially in 2003 from 2002.
Consumer Accounts
Consumer accounts expense decreased by $281 thousand, or 5%, in 2004
from 2003 due to the recovery of previously recorded bad debt expense through
capital credits. Consumer accounts expense did not vary materially in 2003 from
2002.
Administrative, General and Other
Administrative, general and other expenses decreased by $4.0 million,
or 15%, in 2004 from 2003 due to the $1.8 million write down of an impaired
asset and the $965 thousand write-off of several studies in 2003 not recurring
in 2004. The decrease is also due to $1.9 million associated with the
aforementioned update to the method used to record maintenance costs, as well as
$1.6 million associated with the completion of the amortization of a large
portion of the Year 2000 (Y2K) software costs. These decreases, however, were
offset by $757 thousand associated with an improvement in the process of
recording workers compensation claims, $594 thousand associated with our
performance incentive program and $457 thousand associated with the write-off of
obsolete inventory and cancelled projects. Administrative, general and other
expenses increased by $4.1 million, or 18.5%, in 2003 from 2002 due to a $1.8
million write down of an impaired asset, a $500 thousand write-off of the Kenai
Lake PCBs study and a $465 thousand write-off of the Southern Intertie study, a
$387 thousand increase in allocated information services costs, a $445 thousand
increase in insurance costs and a $207 thousand donation of an obsolete
inventory item.
Depreciation
We use remaining life rates set forth in the most recent depreciation
study. In 2003 an update of the Depreciation Study was completed utilizing
Electric Plant in Service balances as of December 31, 2002. The new rates were
implemented and in effect for all of 2004. The new rates are currently under
review by the RCA. Depreciation expense did not vary materially in 2004 from
2003 or in 2003 from 2002.
Interest
Interest on long-term obligations decreased by $1.1 million, or 5%, in
2004 from 2003 due to lower interest rates. Interest on long-term obligations
decreased $3.1 million, or 12% in 2003 from 2002, also due to lower interest
rates.
Interest on short-term borrowing decreased by $11.9 thousand, or 100%,
in 2004 from 2003 due to the line of credit not being utilized during 2004.
Interest on short-term borrowing decreased $287.0 thousand, or 96% in 2003 from
2002, due to a decrease in short-term borrowing, as well as decreased interest
rates.
Interest charged to construction increased by $81.2 thousand, or 20%,
in 2004 from 2003 due to a higher average balance in Construction Work in
Progress (CWIP) caused by the South Anchorage Substation project and the new
138kV transmission line being built between the International substation and the
South Anchorage Substation. Net interest expense includes interest on long-term
obligations and short-term obligations, reduced by interest charged to
construction.
Patronage Capital (Equity)
The following table summarizes our patronage capital and total equity
position for the years ended December 31:
2004 2003 2002
---- ---- ----
Patronage capital at beginning of year $126,341,413 $120,148,502 $125,184,374
Retirement of capital credits
and estate payments (3,193,600) (60,209) (3,019,722)
Assignable margins 7,602,456 6,253,120 (2,016,150)
--------- --------- -----------
Patronage capital at end of year 130,750,269 126,341,413 120,148,502
Other equity* 8,248,530 7,874,709 7,329,393
--------- --------- ---------
Total equity at end of year $138,998,799 $134,216,122 $127,477,895
============ ============ ============
* Other equity includes memberships, donated capital and gain on capital credit retirements.
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. The Board of Directors may also
return capital credits to former members and estates who have requested early
retirements at discounted rates under a discounted capital credits retirement
plan authorized by the Board in September 2002. In 2004, the Board of Directors
authorized the retirement of $3,126,560 of retail patronage for 1985 and 1986.
The Board of Directors also, in 2004, authorized $125,000 for capital credits
payments to those former members and estates who requested early retirements at
discounted rates. In 2003, the Board of Directors was unable to authorize a
capital credit retirement due to covenant restrictions contained in the Amended
and Restated Indenture. In 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
was contained in the Chugach business plan. However, in 2000 we implemented a
plan to return the capital credits of wholesale and retail customers on a
15-year rotation.
The Amended and Restated Indenture prohibits us from making any
distributions, payment or retirement of patronage capital to our customers if an
event of default under the Amended and Restated 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.
Under our Master Loan Agreement with CoBank, we also may not declare or
pay any dividend or make any distributions to members or retirements of
patronage capital if, giving effect to such distribution an event of default
under the Master Loan Agreement exists, or our equities and margins as of the
end of our most recent fiscal quarter would be less than thirty percent (30%) of
the sum of our total long-term debt plus equities and margins at that time.
However, as long as no event of default exists under the Master Loan Agreement
with CoBank and the ratio of our equities and margins to the sum of total
long-term debt plus equities and margins would not be less than 22%, we may make
a distribution of up to the lesser of five percent (5%) of our aggregate
equities and margins as of the end of the immediately preceding fiscal year or
fifty percent (50%) of the prior fiscal year's margins.
The table below sets forth a five-year summary of anticipated capital
credit retirements based on 50% of prior year's margins retirement criteria:
Year Ending Total
2005 $3,000,000
2006 3,500,000
2007 5,500,000
2008 5,000,000
2009 5,500,000
Changes in Financial Condition
Assets
Total assets increased $563.1 thousand, or 0.1%, from December 31,
2003, to December 31, 2004. The net increase was due to a $4.9 million, or 26%
increase in accounts receivable due to higher fuel costs and increased sales to
GVEA. The increase was also due to a $1.8 million, or 8%, increase in materials
and supplies caused by the purchase of inventory items in preparation for
scheduled maintenance projects. The increase was offset by a $2.4 million, or
0.5%, decrease in net utility plant caused by an increase in accumulated
depreciation. The increase was also offset by a $2.0 million, or 100%, decrease
in fuel cost under-recovery caused by the collection of fuel costs through the
fuel surcharge mechanism and a $489 thousand, or 100%, decrease in restricted
construction funds. Prepayments in 2004 also decreased $653 thousand, or 45% due
to a deposit on generation maintenance equipment that was prepaid in 2003 and
cash and cash equivalents also decreased $720 thousand, or 6%.
Liabilities and Equities
Changes in total liabilities include a $4.8 million, or 3.6%, increase
in total equities and margins due to margins, net of capital credit retirements,
in 2004 and a $10.4 million, or 187%, increase in current installments of
long-term obligations due to the reclassification of CoBank 2 to current portion
of long-term obligations. Fuel cost over-recovery also increased $2.7 million,
or 100%, due to the over collection of the previous quarter's fuel cost through
the fuel surcharge mechanism. Fuel also increased $3.9 million, or 43%, due to
higher fuel prices. Other current liabilities also increased $631 thousand, or
80%, due to the increase in patronage capital payable caused by the capital
credit retirement in 2004 that did not occur in 2003 and salaries, wages and
benefits increased $644 thousand, or 13% due to merit increases. The increases
were offset by a $20.9 million decrease in long-term obligations due to the
CoBank 2 reclassification discussed above and the installment payments on CoBank
3 and 4. Deferred credits also decreased by $1.3 million, or 34%, due to a
decrease in customer advances on line extension and the return of the Southern
Intertie construction funds. Provision for rate refund also decreased by $671
thousand, or 100%, due to the payment of rate refunds since December 31, 2003.
Inflation
We do not believe that inflation has a significant effect on our
operations.
Contractual Obligations and Commercial Commitments
The following are Chugach's contractual and commercial commitments as
of December 31, 2004:
Contractual cash obligations: (In thousands)
Payments Due By Period
Total 2005 2006-2007 2008-2009 Thereafter
Long-term debt $379,289 $15,931 $18,054 $15,005 $330,299
Short-term debt1 0 0 0 0 0
Bradley Lake2 16,000 4,000 4,000 4,000 4,000
------ ----- ----- ----- -----
Total $395,289 $19,931 $22,054 $19,005 $334,299
Commercial Commitments: (In thousands)
Amount of Commitment
Expiration Per Period
Total 2004 2005-2006 2007-2008 Thereafter
Lines of credit-available * $70 $70 $0 $0 $0
1At December 31, 2004, Chugach had $70 million in lines of credit available with
various financial institutions, which fund capital requirements. At December 31,
2004, there was no outstanding balance on the lines of credit, therefore, the
available borrowing capacity under these lines of credit was $70 million. The
lines of credit were not utilized in 2004.
2Estimated annual costs
Purchase obligations:
Chugach is a participant and has a 30.4% share in the Bradley Lake
hydroelectric project (See "Item 2-Properties-Other Property-Bradley Lake.")
This contract runs through 2041. We have agreed to pay a like percentage of
annual costs of the project, which has averaged $4 million over the past five
years. We believe these costs, adjusted for inflation, reasonably reflect
anticipated future project costs.
Our primary sources of natural gas are the Beluga River Field producers
and Marathon Oil Company (See "Item 2-Properties-Fuel Supply-Beluga River Field
Producers/Marathon.") We have contracts with each of these producers with
varying expiration dates that generally require us to purchase from them all of
our fuel requirements for our Beluga plant. The current phase of these contracts
expires in December 2013. Our fuel costs vary due to the impact of the energy
future indices used to index the price of fuel and are inherently difficult to
predict. We pass fuel costs directly to our wholesale and retail customers
through the fuel surcharge mechanism (See "Item 7-Management's Discussion and
Analysis of Financial Condition and Results of Operations-Results of
Operations-Fuel Surcharge.")
Liquidity And Capital Resources
We satisfy our operational and capital cash requirements primarily
through internally generated funds, a $50 million line of credit from National
Rural Utilities Cooperative Finance Corporation (NRUCFC), which was renewed for
a five-year term on October 15, 2002, and a $20 million line of credit with
CoBank, which expires April 30, 2005, subject to renewal at the discretion of
the parties. At December 31, 2004, there was no outstanding balance with CFC or
CoBank and neither line was utilized in 2004.
On February 1, 2002, Chugach issued $120,000,000 of 2002 Series A Bond
and $60,000,000 of 2002 Series B Bond for the purpose of redeeming $149.3
million in principal amount of the 1991 Series A Bond due 2022 to pay the
redemption premium on the 1991 Series A Bond due 2022 in the amount of $13.6
million and for general working capital. The 2002 Series A Bond will mature on
February 1, 2012, and 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.
The 2002 Series A Bond and the Auction Rate Bond (collectively the
"Bonds") are unsecured obligations, ranking equally with Chugach's other
unsecured and unsubordinated obligations. In addition, Chugach's ability is
limited 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 the Bonds.
Principal maturities and sinking fund payments of our outstanding
indebtedness at December 31, 2004 are set forth below:
Year Ending Sinking Fund Principal maturities
December 31 Requirement Total
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
2008 5,900,000 1,340,725 7,240,725
2009 6,300,000 1,463,358 7,763,358
Thereafter 293,300,000 36,999,447 330,299,447
----------- ---------- -----------
$321,100,000 $58,189,179 $379,289,179
============ =========== ============
During 2004 we spent approximately $27.8 million on
capital-construction projects, net of reimbursements, which includes interest
capitalized during construction. We develop five-year capital improvement plans
that are updated every year. Our capital improvement requirements are based on
long-range plans and other supporting studies and are executed through the
five-year capital improvement program. Set forth below is an estimate of capital
expenditures for the years 2005 through 2009 as contained in the amended Capital
Improvement Plan (CIP), which was approved on March 16, 2005:
2005 $29.7 million
2006 $27.5 million
2007 $16.4 million
2008 $24.9 million
2009 $16.6 million
We expect that cash flows from operations and external funding sources
will be sufficient to cover operational and capital funding requirements in 2005
and thereafter.
Ratings
Our bond ratings remained unchanged in 2004 reflecting the rating
agencies' confidence in Chugach's ability to meet future operational and
financial challenges.
Off-Balance Sheet Arrangements
We have not created, and are not party to, any special-purpose or
off-balance-sheet entities for the purpose of raising capital, incurring debt or
operating parts of our business that are not consolidated into our financial
statements. We do not have any arrangements or relationships with entities that
are not consolidated into our financial statements that are reasonably likely to
materially affect our liquidity or the availability of our capital resources.
Critical Accounting Policies
Our accounting and reporting policies comply with accounting principles
generally accepted in the United States of America. 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. Significant accounting policies are
described in Note 1 to the financial statements (See "Financial Statements and
Supplementary Data."). Critical accounting policies are those policies that
management believes are the most important to the portrayal of Chugach's
financial condition and results of its operations, and require management's most
difficult, subjective, or complex judgments, often as a result of the need to
make estimates about matters that are inherently uncertain. Most accounting
policies are not considered by management to be critical accounting policies.
Several factors are considered in determining whether or not a policy is
critical in the preparation of financial statements. These factors include,
among other things, whether the estimates are significant to the financial
statements, the nature of the estimates, the ability to readily validate the
estimates with other information including third parties or available prices,
and sensitivity of the estimates to changes in economic conditions and whether
alternative accounting methods may be utilized under accounting principles
general accepted in the United States of America. For all of these policies
management cautions that future events rarely develop exactly as forecast, and
the best estimates routinely require adjustment. Management has discussed the
development and the selection of critical accounting policies with Chugach's
Audit Committee. The following policies are considered to be critical accounting
policies for the year ended December 31, 2004.
Electric Utility Regulation
Chugach is subject to regulation by the RCA. The RCA sets the rates
Chugach is permitted to charge customers based on allowable costs. As a result,
Chugach applies Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS 71). Through the
ratemaking process, the regulators may require the inclusion of costs or
revenues in periods different than when they would be recognized by a
non-regulated company. This treatment may result in the deferral of expenses and
the recording of related regulatory assets based on anticipated future recovery
through rates or the deferral of gains or creation of liabilities and the
recording of related regulatory liabilities. The application of Statement No. 71
has a further effect on Chugach's financial statements as a result of the
estimates of allowable costs used in the ratemaking process. These estimates may
differ from those actually incurred by the Company; therefore, the accounting
estimates inherent in specific costs such as depreciation and pension and
post-retirement benefits have less of a direct impact on Chugach's results of
operations than they would on a non-regulated company. As reflected in Note 1 to
the financial statements under "Deferred Charges and Credits", significant
regulatory assets and liabilities have been recorded. Management reviews the
ultimate recoverability of these regulatory assets and liabilities based on
applicable regulatory guidelines. However, adverse legislation and judicial or
regulatory actions could materially impact the amounts of such regulatory assets
and liabilities and could adversely impact Chugach's financial statements.
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. We accounted
for the agreements under SFAS 133. For rate-making purposes, Chugach did not
adjust rates for gains and losses prior to settlement, and the loss on
settlement will be an adjustment to rates over the lives of the associated debt.
This rate-making treatment was approved by the RCA in Order U-01-108(26). (See
"Item 7-Management's Discussion and Analysis of Financial Condition and Results
of Operations-Results of Operations-Rate Regulation and Rates.") Accordingly,
the unrealized gain or loss was not recorded and was treated as a regulatory
asset upon settlement. Accounting for derivatives continue to evolve through
guidance issued by the Derivatives Implementation Group (DIG) of the Financial
Accounting Standards Board. To the extent that changes by the DIG modify current
guidance, the accounting treatment for derivatives may change.
Critical estimates also include provision for rate refunds and
allowance for doubtful accounts. Actual results could differ from those
estimates.
New Accounting Standards
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity. This
Statement establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. Many of those instruments were previously classified as equity. Some of
the provisions of this Statement are consistent with the current definition of
liabilities in FASB Concepts Statement No. 6, Elements of Financial Statements.
The remaining provisions of this Statement are consistent with FASB's proposal
to revise that definition to encompass certain obligations that a reporting
entity can or must settle by issuing its own equity shares depending on the
nature of the relationship established between the holder and the issuer. While
FASB still plans to revise that definition through an amendment to Concepts
Statement 6, FASB decided to defer issuing that amendment until it has concluded
its deliberations on the next phase of this project. That next phase will deal
with certain compound financial instruments including puttable shares,
convertible bonds, and dual-indexed financial instruments.
Chugach implemented SFAS 150 January 1, 2004. The impact of this
Statement on the financial statements was not material.
Outlook
Chugach is currently planning for future resource needs. An Integrated
Resource Plan (IRP) is in development. This effort studies several possible
future scenarios for power sales.
On March 17, 2004, the Chugach Board of Directors authorized the Chief
Executive Officer (CEO) or his designee to enter into an agreement to form a
Joint Action Agency (JAA) that, if implemented, could provide a structure with
which Chugach and other eligible Alaska utilities might jointly acquire, own and
operate certain generation and transmission facilities.
On September 15, 2004, the Chugach Board of Directors authorized the
CEO to undertake all necessary steps to craft a plan to create a single-member
Generation and Transmission (G&T) cooperative that would hold all Chugach G&T
assets, contractual arrangements, and associated debt. Chugach is considering
this option as a way to more effectively track the finances of the G&T functions
and to help address issues in future rate cases involving the relative margin
earning burdens among customer classes.
These two organizational structures are not mutually exclusive.
Effective January 31, 2005, Chugach reorganized its operations into
more distinct business units - Office of the Chief Executive Officer, Generation
and Transmission (G&T) Division, Distribution Division and Corporate Services.
This reorganization was accomplished to more fully recognize the diversity of
Chugach operations and clearly determine the financial and operational
performance of each unit.
The Office of the Chief Executive Officer is responsible for all
corporate level activities including board of director functions, human
resources, risk management, legal matters, labor relations and employee
relations, legislative affairs and all financing activities Chugach may
undertake. The CEO's direct staff is the Chief Financial Officer, Vice
President, Human Resources, General Counsel and Government and External Affairs
Manager. The general managers of the G&T Division and Distribution Division also
report to the CEO.
G&T operations include all power supply functions, transmission
functions, power dispatch and administrative requirements associated with
generation and transmission. The G&T sector is led by Bradley Evans, General
Manager.
Distribution functions include consumer services, public relations and
line operation and maintenance and consumer information and services areas. The
Distribution area is led by Lee Thibert, General Manager.
Corporate Services is comprised of Administration Services, Information
Services, Regulatory Affairs and Accounting. It is responsible for providing
services to all other sectors of Chugach. Corporate Services is led by William
Stewart, Senior Vice President.
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
The following table provides information regarding cash flows for
principal payments on total debt by maturity date (dollars in thousands) as of
December 31, 2004, and 2003:
2004
Fair
Total Debt* 2005 2006 2007 2008 2009 Thereafter Total Value
- ----------- ---- ---- ---- ---- ---- ---------- ----- -----
Fixed rate $10,000 $0 $0 $0 $0 $270,000 $280,000 $309,502
Average
interest rate 7.76% - - - - 6.39% 6.44%
Variable rate $5,931 $6,326 $11,729 $7,241 $7,763 $60,299 $99,289 $99,289
Average
interest rate 3.22% 3.22% 3.66% 3.22% 3.22% 3.77% 3.60%
* Includes current portion
2003
Fair
Total Debt* 2004 2005 2006 2007 2008 Thereafter Total Value
- ----------- ---- ---- ---- ---- ---- ---------- ----- -----
Fixed rate $0 $10,000 $0 $0 $0 $270,000 $280,000 $308,590
Average
interest rate - 7.76% - - - 6.39% 6.44%
Variable rate $5,545 $5,931 $6,326 $11,729 $7,241 $73,063 $109,834 $109,834
Average
interest rate 1.38% 1.38% 1.38% 1.98% 1.38% 2.08% 1.91%
* 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 $59,310, based on $5,931,000 of variable debt outstanding at
December 31, 2004.
To manage interest rate exposure for refinancing the 1991 Series A
Bonds 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 mechanism, 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
Independent Auditors' Report
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association,
Inc. (the Company) as of December 31, 2004 and 2003, and the related statements
of revenue, expenses and patronage capital, and cash flows for each of the years
in the three-year period ended December 31, 2004. These financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards
as established by the Auditing Standards Board (United States) and in accordance
with the auditing standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. The Company is not required to have, nor were we engaged
to perform, an audit of its internal control over financial reporting. Our audit
included consideration of internal control over financial reporting as a basis
for designing audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the
Company's internal control over financial reporting. Accordingly, we express no
such opinion. 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, 2004 and 2003, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2004, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG, LLP
February 11, 2005
Anchorage, AK
Chugach Electric Association, Inc.
Balance Sheets
December 31, 2004 and 2003
Assets 2004 2003
------ ---- ----
Utility plant (notes 1d, 3, 12 and 13):
Electric plant in service $748,484,527 $747,078,372
Construction work in progress 25,278,388 16,560,438
---------- ----------
Total utility plant 773,762,915 763,638,810
Less accumulated depreciation 305,932,001 293,371,966
----------- -----------
Net utility plant 467,830,914 470,266,844
Other property and investments, at cost:
Nonutility property 24,461 3,550
Investments in associated organizations (note 4) 11,768,457 11,381,796
---------- ----------
Total other property and investments 11,792,918 11,385,346
Current assets:
Cash and cash equivalents, including repurchase agreements of
$12,826,644 in 2004 and $12,663,761 in 2003 10,465,004 11,185,086
Cash-restricted construction funds 0 488,846
Special deposits 217,191 222,163
Accounts receivable, less provision for doubtful accounts of
$364,261 in 2004 and $273,793 in 2003 23,740,383 18,812,199
Fuel cost under-recovery (note 1o) 0 2,032,730
Materials and supplies 23,691,509 21,888,794
Prepayments 805,670 1,458,649
Other current assets 260,115 357,265
------- -------
Total current assets 59,179,872 56,445,732
Deferred charges, net (notes 5 and 14) 20,550,883 20,693,581
---------- ----------
Total assets $559,354,587 $558,791,503
============ ============
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Balance Sheets, Continued
December 31, 2004 and 2003
Liabilities & Equities 2004 2003
---------------------- ---- ----
Equities and margins (note 6 and 7):
Memberships $1,202,538 $1,155,818
Patronage capital 130,750,269 126,341,413
Other 7,045,992 6,718,891
--------- ---------
Total equities and margins 138,998,799 134,216,122
Long-term obligations, excluding current installments (notes 8, and 9):
2001 Series A Bonds payable 150,000,000 150,000,000
2002 Series A Bonds payable 120,000,000 120,000,000
2002 Series B Bonds payable 46,200,000 51,100,000
National Bank for Cooperatives promissory notes payable 47,157,786 63,189,179
---------- ----------
Total long-term obligations 363,357,786 384,289,179
Current liabilities:
Current installments of long-term obligations (notes 8 and 9) 15,931,393 5,545,000
Accounts payable 7,890,172 7,676,906
Provision for rate refund (note 2) 0 671,071
Consumer deposits 1,947,511 1,834,752
Fuel cost over-recovery (note 1o) 2,714,345 0
Accrued interest 6,201,769 6,165,790
Salaries, wages and benefits 5,530,740 4,886,600
Fuel 12,919,623 9,006,758
Other current liabilities 1,416,400 785,760
--------- -------
Total current liabilities 54,551,953 36,572,637
Deferred credits (note 10) 2,446,049 3,713,565
--------- ---------
Total liabilities and equities $559,354,587 $558,791,503
============ ============
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Revenues, Expenses and Patronage Capital
Years ended December 31, 2004, 2003 and 2002
2004 2003 2002
---- ---- ----
Operating revenues (notes 2 and 14) $201,246,615 $184,032,413 $171,944,918
Operating expenses:
Fuel (note 14) 64,113,474 48,667,262 46,822,943
Power production 15,070,486 13,961,565 13,500,103
Purchased power 20,579,992 18,244,921 18,750,936
Transmission 6,350,344 4,511,002 3,930,902
Distribution 11,451,931 10,866,251 10,869,335
Consumer accounts 5,308,353 5,589,788 5,594,572
Administrative, general and other 22,476,005 26,520,189 22,251,895
Depreciation 27,989,452 27,792,051 27,649,250
---------- ---------- ----------
Total operating expenses 173,340,037 156,153,029 149,369,936
Interest expense:
On long-term obligations 21,984,371 23,110,239 26,161,891
Charged to construction - credit (492,506) (411,312) (418,078)
On short-term obligations 0 11,901 298,930
- ------ -------
Net interest expense 21,491,865 22,710,828 26,042,743
---------- ---------- ----------
Net operating margins 6,414,713 5,168,556 (3,467,761)
Nonoperating margins:
Interest income 453,606 325,324 774,814
Capital credits, patronage dividends and other 722,947 679,179 897,761
Property gain (loss) 11,190 80,061 (220,964)
------ ------ ---------
Assignable margins 7,602,456 6,253,120 (2,016,150)
Patronage capital at beginning of year 126,341,413 120,148,502 125,184,374
Retirement of capital credits and estate payments (note 6) (3,193,600) (60,209) (3,019,722)
----------- -------- -----------
Patronage capital at end of year $130,750,269 $126,341,413 $120,148,502
============ ============ ============
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Cash Flows
Years ended December 31, 2004, 2003 and 2002
2004 2003 2002
---- ---- ----
Operating activities:
Assignable margins $7,602,456 $6,253,120 $(2,016,150)
Adjustments to reconcile assignable margins to net
cash provided by operating activities:
Provision for rate refund 0 (1,400,000) 7,050,000
Depreciation and amortization 31,586,948 33,780,103 33,472,159
Capitalization of interest (571,013) (487,359) (491,349)
Impairment of long-lived asset 0 1,846,816 0
Property (gains) losses, net (11,190) (80,061) 220,964
Write-off of deferred charges 217,665 1,088,260 0
Other 1,007 1,145 1,568
Changes in assets and liabilities:
(Increase) decrease in assets:
Accounts receivable (4,928,184) 7,598,064 (4,107,864)
Fuel cost recovery 2,032,730 (2,032,730) 3,591,963
Materials and supplies (1,802,715) 1,858,796 (925,587)
Prepayments 652,979 494,702 (1,325,806)
Other assets 102,122 (20,468) (1,044)
Deferred charges (854,481) (1,887,037) (4,479,028)
Increase (decrease) in liabilities:
Accounts payable 213,266 (43,068) (3,292,931)
Provision for rate refund (671,071) (4,978,929) 0
Consumer deposits 112,759 8,487 222,574
Fuel cost payable 2,714,345 (363,862) 363,862
Accrued interest 35,979 (215,316) (996,952)
Salaries, wages and benefits 644,140 (90,994) 132,775
Fuel 3,912,865 1,911,356 (4,469,715)
Other liabilities 630,640 (1,242,178) 127,782
Deferred credits (92,314) (210,681) (15,887,873)
-------- --------- ------------
Net cash provided by operating activities 41,528,933 41,788,166 7,189,348
Investing activities:
Extension and replacement of plant (27,810,212) (26,526,858) (16,859,047)
Purchase of investments in associated organizations (387,668) (419,226) (480,097)
--------- --------- ---------
Net cash used in investing activities (28,197,880) (26,946,084) (17,339,144)
Financing activities:
Net transfer of restricted construction funds 488,846 110,018 (80,993)
Proceeds from long-term obligations 0 0 180,000,000
Repayments of long-term obligations (10,545,000) (5,165,821) (164,638,695)
Repayments of short-term borrowings 0 (6,081,250) 0
Memberships and donations received 373,821 545,316 705,061
Retirement of patronage capital (3,193,600) (60,209) (3,019,722)
Net receipts (refunds) of consumer advances for construction (1,175,202) (289,342) 653,670
----------- --------- -------
Net cash provided by (used in) financing activities (14,051,135) (10,941,288) 13,619,321
------------ ------------ ----------
Net change in cash and cash equivalents (720,082) 3,900,794 3,469,525
Cash and cash equivalents at beginning of year $11,185,086 $7,284,292 $3,814,767
----------- ---------- ----------
Cash and cash equivalents at end of year $10,465,004 $11,185,086 $7,284,292
=========== =========== ==========
Supplemental disclosure of cash flow information
Interest expense paid, including amounts capitalized $21,354,036 $23,076,144 $27,039,695
=========== =========== ===========
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2004 and 2003
(1) Description of Business and Significant Accounting Policies
a. 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 (HEA) 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).
b. 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.
c. 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 (SFAS) No. 71, Accounting for the Effects of Certain
Types of Regulation (SFAS 71).
(1) Description of Business and Significant Accounting Policies (continued)
d. Utility Plant and Depreciation
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. In accordance with SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets (SFAS 144), utility plant is reviewed
for impairment whenever events or changes in circumstances indicate the
carrying amount of an asset may not be recoverable. Recoverability of
assets to be held and used is measured by a comparison of the carrying
amount of an asset to estimated undiscounted future cash flows expected
to be generated by the asset. If the carrying amount of an asset exceeds
its estimated future cash flows, an impairment charge is recognized by
the amount by which the carrying amount of the asset exceeds the fair
value of the asset. Assets to be disposed of are separately presented in
the balance sheet and reported at the lower of the carrying amount or
fair value less costs to sell, and are no longer depreciated. The assets
and liabilities of a disposed group classified as held for sale are
presented separately in the appropriate asset and liability section of
the balance sheet. Chugach performed an analysis of certain generation
assets in the second quarter of 2003 and determined an impairment of an
asset existed. As a result of this analysis, the value of an asset was
reduced by $1,846,816 to its estimated salvage value. This amount is
included in the 2003 Statement of Revenues, Expenses and Patronage
Capital, "Administrative, general and other," category.
Depreciation and amortization rates have been applied on a straight-line
basis and at December 31 are as follows:
Annual Depreciation Rate Ranges
2004 2002-2003
Steam production plant 2.55% - 3.24% 2.55% - 2.80%
Hydraulic production plant 1.63% - 2.94% 0.04% - 1.56%
Other production plant 4.10% - 9.81% 2.67% - 7.62%
Transmission plant 1.72% - 5.26% 1.50% - 4.24%
Distribution plant 2.10% - 9.98% 2.13% - 9.22%
General plant 2.23% - 27.25% 2.21% - 20.40%
Other 2.75% - 2.75% 2.35% - 2.75%
(1) Description of Business and Significant Accounting Policies (continued)
Chugach uses remaining life rates set forth in the most recent
depreciation study. In 2003 an update of the Depreciation Study was
completed utilizing Electric Plant in Service balances as of December 31,
2002. The new rates were implemented and in effect for all of 2004. The
new rates are currently under review by the RCA. Management believes that
any change as a result of the RCA's review will not have a material
impact to the financial statements.
e. Capitalized Interest
Allowance for funds used during construction (AFUDC) and interest charged
to construction - credit (IDC) are the estimated costs during the period
of construction of equity and borrowed funds. Chugach capitalized such
funds at the weighted average rate (adjusted monthly) of 4.6% during
2004, 4.8% during 2003 and 4.7% during 2002.
f. 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.
g. Fair Value of Financial Instruments
SFAS No. 107, Disclosures About the Fair Value of Financial Instruments
(SFAS 107), requires disclosure of the fair value of certain on and off
balance sheet financial instruments for which it is practicable to
estimate that value. The following methods are used to estimate the fair
value of financial instruments:
Cash and cash equivalents and restricted cash - the carrying amount
approximates fair value because of the short maturity of those
instruments.
Investments in associated organizations - the carrying amount
approximates fair value because of limited marketability and the
nature of the investments.
Consumer deposits - the carrying amount approximates fair value
because of the short refunding term.
Long-term obligations - the fair value is estimated based on the
quoted market price for same or similar issues (note 8).
(1) Description of Business and Significant Accounting Policies (continued)
h. 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 133. For rate-making purposes, Chugach did
not adjust rates for gains and losses prior to settlement, and the loss
on settlement will be an adjustment to rates over the lives of the
associated debt. This rate-making treatment was approved by the RCA in
Order U-01-108(26). See note 2, "Regulatory Matters." Accordingly, the
unrealized gain or loss was not recorded and was treated as a regulatory
asset upon settlement (note 6).
i. 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.
j. Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount. The
allowance for doubtful accounts is management's best estimate of the
amount of probable credit losses in existing accounts receivable. Chugach
determines the allowance based on its historical write-off experience and
current economic conditions. Chugach reviews its allowance for doubtful
accounts monthly. Past due balances over 90 days in a specified amount
are reviewed individually for collectibility. All other balances are
reviewed in aggregate. Account balances are charged off against the
allowance after all means of collection have been exhausted and the
potential for recovery is considered remote. Chugach does not have any
off-balance-sheet credit exposure related to its customers.
k. Materials and Supplies
Materials and supplies are stated at average cost.
l. 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
requires that 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.
(1) Description of Business and Significant Accounting Policies (continued)
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.
m. Patronage Capital
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 at the
discretion of the Board of Directors. Retained assignable margins are
designated on Chugach's balance sheet as patronage capital. This
patronage capital constitutes the principal equity of Chugach. The Board
of Directors may also return capital credits to former members and
estates who request early retirements at discounted rates under a
discounted capital credits retirement plan authorized by the Board in
September 2002.
n. Operating Revenues
Revenues are recognized when customers are billed. 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, as
well as purchased power costs.
o. Fuel and Purchased Power Costs
The expenses associated with electric services include fuel used to
generate electricity and power purchased from others. These costs are
expensed as used or purchased. Chugach is authorized by the RCA to
recover fuel and purchased power costs through the fuel surcharge
mechanism, which is adjusted quarterly to reflect increases and decreases
of such costs. Revenues are adjusted for differences between recoverable
fuel costs and amounts actually recovered through rates. Fuel costs were
over-recovered by $2.7 million in 2004 and under-recovered by $2.0
million in 2003. Total fuel and purchased power costs in 2004 and 2003
were approximately $85 million and $67 million, respectively.
(1) Description of Business and Significant Accounting Policies (continued)
p. 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.
q. 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, 2004, 2003 and 2002,
Chugach received no unrelated business income.
r. Reclassifications
Certain reclassifications, which have no affect on assignable margins,
have been made to the 2002 and 2003 financial statements to conform to
the 2004 presentation.
s. New Accounting Pronouncements
In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS
No. 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity (SFAS 150). This Statement
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and
equity. Many of those instruments were previously classified as equity.
Some of the provisions of this Statement are consistent with the current
definition of liabilities in FASB Concepts Statement No. 6, Elements of
Financial Statements. The remaining provisions of this Statement are
consistent with FASB's proposal to revise that definition to encompass
certain obligations that a reporting entity can or must settle by issuing
its own equity shares depending on the nature of the relationship
established between the holder and the issuer. While FASB still plans to
revise that definition through an amendment to Concepts Statement 6, FASB
decided to defer issuing that amendment until it has concluded its
deliberations on the next phase of this project. That next phase will
deal with certain compound financial instruments including puttable
shares, convertible bonds, and dual-indexed financial instruments.
Chugach implemented SFAS 150 effective January 1, 2004. The impact of
this statement on its financial statements was immaterial.
(2) Regulatory Matters
Docket U-01-108
Chugach filed a general rate case on July 10, 2001, based on the 2000
test year and subsequently implemented interim and refundable rate
increases as approved by the RCA. 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%.
Three wholesale customers and the Public Advocacy staff of the RCA
participated in the rate case.
Order No. 26
On February 6, 2003, Chugach received Order U-01-108(26) (Order 26) from
the RCA.
Order 26 required a refund of revenues collected in 2001 of approximately
$1.1 million and revenues collected in 2002 of approximately $6.0
million, which resulted in a net operating loss of approximately $2
million in 2002. Under the Order, Chugach's financial performance for
2002 fell below the 1.10 level contained in the Rate Covenants in its
currently effective indenture, the Amended and Restated Indenture, the
CoBank Master Loan Agreement and the MBIA Insurance Corporation's (MBIA)
Reimbursement and Indemnity Agreement. (Note 8)
In accordance with the Rate Covenant in the Amended and Restated
Indenture, on February 13, 2003, Chugach filed a Motion with the RCA
asking the RCA to stay the effect of Order 26 until after the RCA
considered Chugach's Petition for Reconsideration. On February 18, 2003,
the RCA granted, in part, Chugach's motion for stay. Chugach filed the
Petition for Reconsideration with the RCA on February 28, 2003.
Order No. 30
On April 14, 2003, the RCA issued Order No. 30 in Docket U-01-108,
significantly revising its earlier ruling. On April 28, 2003 Chugach
submitted a revised revenue requirement and cost of service study in
compliance with RCA Order No. 30. This order increased Chugach's revenue
requirement by $3.1 million and adjusted the required refund from $7.1
million to $1.9 million.
Order No. 33
On August 26, 2003, the RCA issued Order No. 33 and accepted Chugach's
April 28, 2003, compliance filing subject to reducing long-term interest
expense by $1.2 million associated with AFUDC/IDC. In Order No. 33, the
RCA re-reversed its earlier decision regarding the treatment of
AFUDC/IDC.
(2) Regulatory Matters (continued)
Order No. 36
Effective November 7, 2003, the RCA approved Chugach's compliance filing
and final rates in this docket. As a result, and in relation to
prior-approved permanent rates, Chugach's rates on a system basis
increased 0.07 percent, or an increase of 3.5 percent to retail customers
and a decrease of 7.9 percent to wholesale customers.
The results of the RCA's decision on final rates were implemented on
November 10, 2003.
Appeal of RCA Orders
Chugach filed a timely appeal of RCA Orders Nos. 26, 30 and 33 to the
Alaska Superior Court. In its Appellant's brief dated February 18, 2004,
Chugach asserted that the RCA's orders contained three errors:
o The split TIER decision unduly discriminates against retail
customers;
o Interest expense was allocated on the basis of plant
associated with G&T and Distribution rather than on the basis
of debt associated with each function; and
o Chugach is entitled to include all of its interest expense in
rates and the RCA's offset for Interest During Construction
(IDC) was not justified because nearly all of the plant that
produced the IDC was in service by the time the new rate went
into effect.
The resolution of the first two issues would not have changed the total
amount Chugach could have recovered through rates. If Chugach had
prevailed on the last issue, it would have been authorized to recover
approximately $1,000,000 more each year in rates.
One of Chugach's wholesale customers, MEA, also appealed the RCA's
orders. In its Appellant's brief, MEA argued that the RCA's decision to
normalize Chugach's variable rate debt at 3.8 percent and to authorize
the corresponding interest expense constitutes error based on the
historical rates prevailing for Chugach's variable rate debt. If MEA had
prevailed on its argument, Chugach's authorized rates would have been
reduced by approximately $1,000,000 each year.
After oral argument on October 8, 2004, the Alaska Superior Court upheld
all decisions of the RCA.
(2) Regulatory Matters (continued)
Provision For Rate Refund
At December 31, 2002, Chugach recorded a provision for rate refund of
$7.1 million. On April 15, 2003, the RCA issued Order No. 30 in Docket
U-01-108, significantly revising its earlier ruling in which $5.2 million
of that provision was reversed. Between March and November of 2003,
additional provisions were recorded in the amount of $3.8 million
reflecting RCA decisions through Order No. 30, in addition to RCA orders
that continued through the period. In October and November of 2003,
Chugach's wholesale customers were refunded $5.0 million. Between March
19 and April 19, 2004, Chugach issued refunds totaling $0.6 million to
its Small General Service class for customer bills rendered between
January 31 and November 10, 2003.
(3) Utility Plant
Major classes of electric plant as of December 31 are as follows:
2004 2003
---- ----
Electric plant in service:
Steam production plant $60,462,671 $60,392,869
Hydraulic production plant 18,180,685 17,990,505
Other production plant 132,449,993 109,737,781
Transmission plant 222,338,304 215,716,581
Distribution plant 213,119,035 202,573,670
General plant 53,636,315 54,871,238
Unclassified electric plant in service* 39,575,890 77,256,535
Other 8,721,634 8,539,193
--------- ---------
Total electric plant in service 748,484,527 747,078,372
Construction work in progress 25,278,388 16,560,438
---------- ----------
Total electric plant in service
and construction work in progress $773,762,915 $763,638,810
============ ============
*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.
(4) Investments in Associated Organizations
Investments in associated organizations, which are non-marketable and
accounted for at cost, include the following at December 31:
2004 2003
---- ----
National Rural Utilities Cooperative Finance Corporation
(NRUCFC) 6,095,980 6,095,980
National Bank for Cooperatives (CoBank) 5,513,192 5,125,524
NRUCFC capital term certificates 42,662 43,647
Other 116,623 116,645
------- -------
$11,768,457 $11,381,796
=========== ===========
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.
(5) Deferred Charges
Deferred charges, net of amortization, consisted of the following at
December 31:
2004 2003
---- ----
Debt issuance and reacquisition costs $10,981,260 $12,569,713
Refurbishment of transmission equipment
216,050 225,309
Computer software and conversion 740,771 516,249
Studies (note 14) 4,646,181 2,942,082
Business venture studies 172,578 172,216
Fuel supply negotiations 256,030 278,745
Major overhaul of steam generating unit 1,895,329 2,287,466
Environmental matters and other 74,304 88,071
Other regulatory deferred charges 1,568,380 1,613,731
--------- ---------
$20,550,883 $20,693,581
=========== ===========
At December 31, 2004 and 2003, $5.6 million and $3.6 million,
respectively, of total deferred charges represent regulatory assets in
progress and are not currently being amortized. The majority of these
charges represent costs associated with the Cooper Lake Power Plant FERC
re-licensing effort.
(6) Patronage Capital
Chugach has an approved capital credit retirement policy, which is
contained in the Chugach Financial Management 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,
2004, Chugach had assigned $117,979,257 of patronage capital (net of
capital credit retirements). Approval of actual capital credit
retirements is at the discretion of Chugach's Board of Directors. Chugach
records a liability when the retirements are approved by the Board of
Directors.
In November 2002, the Board of Directors authorized the retirement of
$2,769,568 of retail patronage for 1985.
In 2003, the Board of Directors was unable to authorize a capital credit
retirement due to covenant restrictions contained in the Amended and
Restated Indenture of Trust. (Note 8)
In November 2004, the Board of Directors authorized the retirement of
$3,126,560 of retail patronage for 1985 and 1986.
In December 2004, the Board of Directors authorized $125,000 for capital
credits payments to those former members and estates who have requested
early retirements at discounted rates under the discounted capital
credits retirement plan authorized by the Board in September 2002.
Estate payments in the amount of $121,629, $60,209 and $250,154 were made
in 2004, 2003 and 2002, respectively.
Following is a five-year summary of anticipated capital credit
retirements:
Year ending Total
December 31,
2005 $ 3,000,000
2006 $ 3,500,000
2007 $ 5,500,000
2008 $ 5,000,000
2009 $ 5,500,000
(7) Other Equities
A summary of other equities at December 31 follows:
2004 2003
---- ----
Nonoperating margins, prior to 1967 $23,625 $23,625
Donated capital 249,624 183,633
Unclaimed capital credit retirement 6,772,743 6,511,633
--------- ---------
$7,045,992 $6,718,891
(8) Debt
Long-term obligations at December 31 are as follows: 2004 2003
---- ----
CoBank 7.76% fixed rate note maturing in 2005, with interest payable monthly
$10,000,000 $10,000,000
CoBank 3.81% variable rate note maturing in 2022, with interest payable
monthly and principal due annually beginning in 2003 43,189,179 44,134,179
CoBank 3.81% variable rate note, with principal due in 2007, and with
interest payable monthly 5,000,000 10,000,000
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
2002 Series A Bond of 6.20%, maturing in 2012, with interest payable
semi-annually February 1 and August 1: 120,000,000 120,000,000
2002 Series B Bond of a rate set for 28-day auction periods, maturing in
2012, with interest payable monthly and principal due annually 51,100,000 55,700,000
---------- ----------
Total long-term obligations 379,289,179 389,834,179
Less current installments 15,931,393 5,545,000
---------- ---------
Long-term obligations, excluding current installments $363,357,786 $384,289,179
============ ============
(8) 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. 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 the Amended and
Restated Indenture pursuant to which the bonds became unsecured
obligations of Chugach.
Chugach is also required to comply with the Master Loan Agreement between
Chugach and CoBank dated 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.
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.
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.
(8) Debt (continued)
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
under "Covenants" above, Chugach received a waiver of the rate covenant
from CoBank. Margins for interest generally consist of Chugach's
assignable margins plus 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 adjustments to those rates so that they would
generate revenues reasonably 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 took the actions described in note
2, "Regulatory Matters."
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.
(8) Debt (continued)
Maturities of Long-term Obligations
Long-term obligations at December 31, 2004, mature as follows:
Year ending Sinking Fund Sinking Fund Sinking Fund Principal Maturities Total
December 31 Requirements Requirements Requirements
2001 Series A 2002 Series A 2002 Series B CoBank Promissory
-------------- -------------- -------------- -----------------
Bonds Bonds Bonds Notes
----- ----- ----- -----
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
2008 0 0 5,900,000 1,340,725 7,240,725
2009 0 0 6,300,000 1,463,358 7,763,358
Thereafter 150,000,000 120,000,000 23,300,000 36,999,447 330,299,447
----------- ----------- ---------- ---------- -----------
$150,000,000 $120,000,000 $51,100,000 $58,189,179 $379,289,179
============= ============= ============ =========== ============
Short-term obligations
Chugach had an annual line of credit of $20,000,000 available at December
31, 2004 and 2003, with CoBank. The CoBank line of credit expires April
30, 2005. Chugach anticipates renewing the CoBank line of credit for
2005. Chugach did not utilize this line of credit in 2004. At December
31, 2004 and 2003, there was no outstanding balance on this line of
credit. In addition, Chugach had an annual line of credit of $50,000,000
available at December 31, 2004 and 2003, with NRUCFC. Chugach did not
utilize this line of credit in 2004. At December 31, 2004 and 2003, 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 $120,000,000 of 2002 Series A Bond
and $60,000,000 of 2002 Series B Bond for the purpose of redeeming $149.3
million in principal amount of the 1991 Series A Bond due 2022 to pay the
redemption premium on the 1991 Series A Bond due 2022 in the amount of
$13.6 million and for general working capital. The 2002 Series A Bond
will mature on February 1, 2012, and 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.
(8) Debt (continued)
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.
The 2002 Series A Bond and the Auction Rate Bond (collectively the
"Bonds") are unsecured obligations, ranking equally with Chugach's other
unsecured and unsubordinated obligations. In addition, Chugach's ability
is limited 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 the Bonds.
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).
(9) 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:
2004 2003
---- ----
Carrying Fair Carrying Fair
Value Value Value Value
Long-term obligations
(including current installments) $379,289 $408,791 $389,834 $418,424
Fair value estimates are dependent upon subjective assumptions and
involve significant uncertainties resulting in variability in estimates
with changes in assumptions.
(10) Deferred Credits
Deferred credits at December 31 consisted of the following:
2004 2003
---- ----
Refundable consumer advances for construction $1,353,069 $2,528,271
Estimated initial installation costs for transformers and meters 387,336 369,153
Post retirement benefit obligation 480,900 405,700
Other 224,744 410,441
------- -------
$2,446,049 $3,713,565
========== ==========
(11) 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 $2,565,000 in 2004, $2,529,000 in 2003 and $2,253,000 in
2002. In 2004, 2003 and 2002, Chugach contributed $1,638,000, $1,492,000
and $1,401,000, respectively, to the NRECA plan.
(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 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
$41,000,000. Under a worst-case scenario, Chugach could be faced with
annual expenditures of approximately $4.7 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%.
The following represents information with respect to Bradley Lake at June
30, 2004 (the most recent date for which information is available).
Chugach's share of expenses was $4,205,657 in 2004, $4,212,072 in 2003
and $4,343,562 in 2002 and is included in purchased power in the
accompanying financial statements.
(In thousands) Total Proportionate Share
----- -------------------
Plant in service $ 308,966 $ 93,926
Accumulated depreciation (88,385) (26,869)
Interest expense 8,782 2,670
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
Anchorage Municipal Light & Power (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.
On January 22, 2004, the Eklutna Operating Committee voted to remove MEA
as the operator of the plant. Chugach will provide personnel for the
daily operation and maintenance of the power plant. ML&P will continue to
perform major maintenance at the plant. Chugach personnel will perform
daily plant inspections, meter reading, monthly report preparation, and
other activities as required.
(14) Commitments, Contingencies and Concentrations
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 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. The committed volumes for the 2015 contract should be used
by early 2011. The currently priced volumes for the 2025 contract should
also be used by early 2011, however, there is an additional 120 BCF
reserved if satisfactory term and conditions can be negotiated. For 2004,
86% of our power was generated from gas, and 86% of that gas-fired
generation took place at Beluga.
Concentrations
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.
(14) Commitments, Contingencies and Concentrations (continued)
Chugach is the principal supplier of power under long-term wholesale
power contracts with MEA and HEA. These contracts represented $62.0
million or 31.2% of operating revenues in 2004, $55.8 million or 30.8% in
2003 and $57.0 million or 33.7% in 2002. These contracts will expire in
2014.
Fuel is purchased directly from Marathon Oil Company, ChevronTexaco, ML&P
and ConocoPhillips. The following represents the cost of fuel purchased
from these vendors as a percentage of total fuel costs for the years
ended December 31:
2004 2003 2002
---- ---- ----
Marathon Oil Company 48.8% 47.4% 45.6%
Chevron Texaco 19.5% 20.0% 20.6%
ML&P 15.8% 16.2% 16.6%
ConocoPhillips 15.8% 16.2% 16.6%
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. In an 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. The costs of PCB
sampling and analysis in Kenai Lake were accounted for as an expense.
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. All of MEA's claims were
dismissed by the Superior Court. 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. We
cross-appealed the Superior Court's decision not to dismiss the financial
management claim on jurisdictional and res judicata grounds.
(14) Commitments, Contingencies and Concentrations (continued)
The Alaska Supreme Court, on October 8, 2004, ruled in Chugach's favor
supporting its right under the power sales agreement to file for interim
rate relief without first going to the Joint Committee. The Supreme Court
ruled against Chugach by overturning the Superior Court's decision that
dismissed MEA's claim asking for review of Chugach's management of use of
rate locks instead of defeasing debt based on the Prudent Utility
Practice standard under our power sales agreement. The Supreme Court
remanded this issue to the Superior Court.
On January 24, 2005, Chugach filed a summary judgment motion based on
Chugach's claim that in the 2000 Test Year rate case the RCA has already
decided the underlying issues relating to the prudency of Chugach's use
of rate locks instead of defeasing debt. This motion is pending.
Management is uncertain of the outcome of the proceeding before the
Superior Court.
Matanuska Electric Association, Inc. v. Chugach Electric Association,
Inc. Superior Court Case No. 3AN-04-11776 Civil
On October 12, 2004, MEA filed suit in Superior Court alleging a breach
of the power sales agreement between the parties and violation of
Chugach's bylaws in connection with allocation of margins (capital
credits) to MEA for the years 1998 through 2003. Allocation of capital
credits assigns a share of the margins earned in a particular year to
each customer. Capital credits are repatriated to customers at the
discretion of the board of directors typically many years after the
margins are earned.
The suit seeks a declaration by the Court that Chugach is in breach of
its bylaws and the power sales agreement based on its allocation of
capital credits to MEA as well as injunctive relief requiring Chugach to
calculate MEA's capital credit allocations based on MEA's patronage and
in accordance with generally accepted accounting practices for nonprofit
cooperatives and cooperative principles. The suit also seeks damages in
an unspecified amount to compensate MEA for the alleged breach of
contract.
Management intends to vigorously defend against the claim. Management is
uncertain of the outcome of the suit.
Other
Chugach received a demand letter from a third party offering a license to
a patent and implying that the patent may be infringed by certain
services provided by Chugach. The patent purportedly relates to
intellectual property rights over a system for automated electronic bill
presentment and payment. As of this date, no legal proceedings have been
instituted against us, but if the third party's patents are valid,
enforceable and apply to our business, we could be required to seek a
license, discontinue certain activities or be subject to a claim for past
infringement. We are currently considering this matter, but lack
(14) Commitments, Contingencies and Concentrations (continued)
sufficient information to assess the potential outcome at this time.
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 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
changed since its inception (November 1992) from an initial rate of
$0.000626 per kWh to the current rate of $0.000397, effective October 1,
2004.
(15) Quarterly Results of Operations (unaudited)
2004 Quarter Ended
Dec. 31 Sept. 30 June 30 March 31
------- -------- ------- --------
Operating Revenue $55,221,563 $47,991,700 $46,388,411 $51,644,941
Operating Expense 46,010,061 43,778,224 41,441,061 42,110,691
Net Interest 5,512,148 5,373,404 5,254,092 5,352,221
--------- --------- --------- ---------
Net Operating Margins 3,699,354 (1,159,928) (306,742) 4,182,029
Non-Operating Margins 805,322 145,698 122,788 113,935
------- ------- ------- -------
Assignable Margins $4,504,676 $(1,014,230) $(183,954) $4,295,964
========== ============ ========== ==========
2003 Quarter Ended
Dec. 31 Sept. 30 June 30 March 31*
------- -------- ------- ---------
Operating Revenue $50,940,575 $41,163,160 $41,689,671 $50,239,007
Operating Expense 44,326,751 38,351,606 38,320,588 35,154,084
Net Interest 5,321,421 5,734,622 5,870,169 5,784,616
--------- --------- --------- ---------
Net Operating Margins 1,292,403 (2,923,068) (2,501,086) 9,300,307
Non-Operating Margins 614,311 153,236 91,100 225,917
------- ------- ------ -------
Assignable Margins $1,906,714 $(2,769,832) $(2,409,986) $9,526,224
========== ============ ============ ==========
*The increase to operating revenue described in note 2 "Regulatory Matters"
was recorded in the 2003 quarter ended March 31.
Item 9 - Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure
None
Item 9A - Disclosure Controls and Procedures
Evaluation of Controls and Procedures
As of the end of the period covered by this report, we evaluated the
effectiveness of the design and operation of our disclosure controls and
procedures. Our chief executive officer (CEO) and chief financial officer (CFO)
supervised and participated in this evaluation. Based on this evaluation, our
CEO and CFO each concluded that our disclosure controls and procedures are
effective in timely alerting them to material information required to be
included in our periodic reports to the SEC. The design of any system of
controls is based in part upon various assumptions about the likelihood of
future events, and there can be no assurance that any of our plans, products,
services or procedures will succeed in achieving their intended goals under
future conditions. In addition, there have been no significant changes in our
internal controls or in other factors known to management that could
significantly affect our internal controls subsequent to our most recent
evaluation.
Item 9B - Other Items
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 Chief Executive Officer. Our seven-member Board of Directors
sets policy and provides direction to the Chief Executive Officer. The following
table sets forth certain information with respect to our executive officers and
directors.
Name Age Position
Evan J. Griffith............................ 63 Chief Executive Officer
Lee D. Thibert.............................. 49 General Manager, Distribution Division
Michael R. Cunningham....................... 55 Chief Financial Officer
William R. Stewart.......................... 58 Sr. Vice President, Services Division
Bradley W. Evans............................ 50 General Manager, G&T Division
H. A. (Red) Boucher......................... 84 Chairman and Director
Bruce Davison............................... 56 Vice Chairman and Director
Patricia B. (Pat) Jasper.................... 75 Secretary and Director
Jeffrey W. Lipscomb......................... 54 Treasurer and Director
Samuel W. Cason............................. 45 Director
Christopher Birch........................... 54 Director
David Cottrell.............................. 57 Director
Executive Officers
Evan J. Griffith was appointed Chief Executive Officer 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 General Manager, Distribution Division in
a January 31, 2005, reorganization. Prior to that appointment he had served as
Sr. Vice President, Power Delivery since June 3, 2002. Prior to that, he had
served as Executive Manager, Transmission & Distribution Network Services since
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 Sr. Vice President, Services Division
in a January 31, 2005, reorganization. Prior to that appointment he had served
as Sr. Vice President, Administration since June 5, 2002. Prior to that, he had
served as Executive Manager, Retail Services since a 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 General Manager, G&T Division in a
January 31, 2005, reorganization. Prior to that appointment he had served as Sr.
Vice President, Energy Supply since June 5, 2002. Prior to that, he had served
as Director of Energy Supply since February 26, 2001. Prior to his current
Chugach employment, Mr. Evans served as Manager, System Dispatch for Golden
Valley Electric Association.
Board of Directors
Bruce Davison serves as Vice Chairman of the Board and also chairs the
board's Operations Committee. He has served as board Chairman and Secretary. 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 an attorney and
professional engineer and a partner in the law firm of Davison & Davison, Inc.
Red Boucher serves as Chairman of the Board. He has served on the board
since 1999 and has previously served as Vice Chairman and Vice President. In
addition to being a director, Mr. Boucher is a communications consultant who
owns a consulting firm. He has held many elected offices including Lieutenant
Governor of Alaska.
Pat Jasper serves as Secretary of the Board. She 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
former computer programmer and systems analyst.
Jeff Lipscomb was elected director in April 2000 and currently serves
as Treasurer and chairs the board's Finance committee. Mr. Lipscomb is a project
management consultant with JWL Engineering. He is a professional mechanical
engineer with over 20 years of experience in Alaskan oil and gas production
facility design.
Dave Cottrell has served on the board since 2001 and currently chairs
the board's Audit committee. He has previously served as Vice President of the
Board. Mr. Cottrell is a founding member and past managing partner of Mikunda
Cottrell & Co., Certified Public Accountants. He is currently the president and
managing director of Mikunda, Cottrell, Accountants and Consultants.
Chris Birch was appointed to fill a board vacancy in 1996 and
re-elected to that seat in 1997, 2000 and 2003. He has served as board Secretary
and President and currently chairs the board's Technology committee. Mr. Birch
is a professional civil engineer, licensed in Alaska since 1978 and recently
retired as Director of Engineering, Environment and Planning at the Ted Stevens
Anchorage International Airport. He is currently a senior engineer with Tryck
Nyman Hayes, Inc.
Sam Cason is a self-employed attorney. He was elected to a 3-year term
on the board in 2002 and currently chairs the board's Government and External
Affairs committee.
Code of Ethics
Chugach developed a code of ethics that applies to its principal
executive officer, principal financial officer, principal accounting officer and
any person performing similar functions. The code of ethics was finalized June
16, 2004. It is also posted on Chugach's website at www.chugachelectric.com.
Audit Committee Financial Expert
Chugach is a cooperative and each board member must be a member of the
cooperative. The Board of Directors relies on the advice of all members of the
Finance and Audit Committees, therefore the Board of Directors has not formally
designated an Audit Committee financial expert.
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 2004, and for all such
executive officers as a group:
Name Principal Position Year Total Remuneration Bonus Total
Evan J. Griffith Chief Executive Officer 2004 $216,073 $14,848 $230,921
2003 $201,685 - $201,685
2002 $172,239 - $172,239
Lee D. Thibert General Manager, 2004 $170,312 $8,158 $178,470
Distribution Division 2003 $149,103 $5,939 $155,042
2002 $154,881 - $154,881
Michael R. Cunningham Chief Financial Officer 2004 $155,955 - $155,955
2003 $132,316 - $132,316
2002 $130,220 - $130,220
William R. Stewart Sr. Vice President, 2004 $182,741 $5,438 $188,179
Services Division 2003 $161,879 $3,712 $165,591
2002 $159,839 - $159,839
Bradley W. Evans General Manager, 2004 $148,137 $7,154 $155,291
G&T Division 2003 $135,398 $5,197 $140,595
2002 $128,227 - $128,227
Directors are compensated for their services at the rate of $200 per
board meeting or other meeting at which they are representing the Association in
an official capacity within the State of Alaska, and $250 per day when attending
meetings outside the State, including each day of travel, plus reasonable out of
pocket expenses, up to a maximum of 70 meetings per year for a director and 85
meetings per year for the Chairman.
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 or she completes 1,000 hours of service either in his or her 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
or she 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 or she 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 or her normal retirement date provided he
or she 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 or her years of
participation in the Plan (benefit service) and the highest five-year average of
the annual rate of his or her base salary during the last ten years of his or
her 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 or her normal retirement date is equal to the product of
his or her years of benefit service 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, 2004 taken into account under the
Plan for the executive officers is shown below. Base salary for 2004 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 Chief Executive Officer 14 years, 4 months $193,066
Lee D. Thibert General Manager, Distribution
Division 16 years, 7 months 152,006
Michael R. Cunningham Chief Financial Officer 21 years, 1 month 136,572
William R. Stewart* Sr. Vice President, Services
Division 2 year, 2 months 146,016
Bradley W. Evans General Manager, General
Manager, G&T Division 3 years, 10 months 142,002
* 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 March 2004, the Board of Directors authorized the renewal of the
employment agreement with Evan J. Griffith, our Chief Executive Officer, for two
years with an additional one-year option. He is paid an annual base salary of
$193,066. Mr. Griffith is also 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 - Principal Accountant Fees and Services
The Audit Committee of the Board of Directors retained KPMG LLP as the
independent certified public accountants for Chugach during the fiscal year
ended December 31, 2004.
Fees and Services
KPMG LLP has provided certain audit, audit-related, tax and non-audit
services, the fees for which are as follows:
2004 2003
---- ----
Audit services and quarterly reviews $93,075 $65,400
Audit-related services (registration statement) $0 $0
Non-audit services:
Single audit and employee benefit plans $8,250 $15,850
Tax consulting and return preparation $2,250 $2,500
The Audit Committee of the Board of Directors has a policy to
pre-approve all invoices by Chugach's independent public accountants. All
invoices from KPMG LLP for fiscal years ended December 31, 2004 and 2003 were
approved by the Audit Committee.
PART IV
Item 15 - Exhibits and Financial Statement Schedules
Page
Financial Statements
Included in Part IV of this Report:
Independent Auditors' Report 37
Balance Sheets, December 31, 2004 and 2003 38-39
Statements of Revenues, Expenses and Patronage Capital,
Years ended December 31, 2004, 2003 and 2002 40
Statements of Cash Flows,
Years ended December 31, 2004, 2003 and 2002 41
Notes to Financial Statements 42-64
Financial Statement Schedules
Included in Part IV of this Report:
Independent Auditors' Report 74
Schedule II - Valuation and Qualifying Accounts,
Years ended December 31, 2004, 2003 and 2002 75
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. (the Company) as of December 31, 2004 and 2003, 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, 2004. 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 Company'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 generally accepted auditing standards
as established by the Auditing Standards Board (United States) and in accordance
with the auditing standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. The Company is not required to have, nor were we engaged
to perform, an audit of its internal control over financial reporting. Our audit
included consideration of internal control over financial reporting as a basis
for designing audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the
Company's internal control over financial reporting. Accordingly, we express no
such opinion. 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, 2004 and 2003, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2004, in conformity with U.S. generally accepted accounting principles. Also, in
our opinion, the related financial statement schedule, when considered in
relation to the basic financial statements taken as a whole, presents fairly, in
all material respects, the information set forth therein.
/s/ KPMG, LLP
Anchorage, Alaska
February 11, 2005
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, 2004 (273,793) (202,533) 112,065 (364,261)
December 31, 2003 (313,545) (326,842) 366,594 (273,793)
December 31, 2002 (318,757) (344,472) 349,684 (313,545)
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. (18)
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 2001 Series A Bond due 2011. (11)
4.15 Form of 2002 Series A Bond due 2012. (14)
4.16 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)
10.5.1 Assignment of 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 June
30, 2003. (19)
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)
10.24.1 Partial Assignment of Bradley Lake Hydroelectric Project 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 June
30, 2003. (19)
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)
10.25.1 Partial Assignment of Bradley Lake Hydroelectric Project 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 June 30, 2003. (19)
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)
10.29.1 Assignment of 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 June 30,
2003. (19)
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)
10.39.2 Assignment of Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and
Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
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 Amendment to Line of Credit Agreement between the Registrant and
CoBank, ACB dated December 27, 2002. (18)
10.45.1 Master Loan Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (17)
10.45.2 Promissory Note and Consolidating Term Loan Supplement between the Registrant and CoBank, ACB dated
December 27, 2002. (17)
10.47 Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance
Corporation dated October 15, 2002. (17)
10.52 Employment Agreement between the Registrant and Evan J. Griffith dated effective April 21, 2004. (20)
14 Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. (21)
31.1 Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 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.
(17) Previously filed as an exhibit to the Registrant's
Annual Report on Form 10-K dated December 31, 2002.
(18) Previously filed as an exhibit to the Registrant's
Quarterly Report on Form 10-Q dated March 31, 2003.
(19) Previously filed as an exhibit to the Registrant's
Annual Report on Form 10-K dated December 31, 2003.
(20) Previously filed as an exhibit to the Registrant's
Quarterly Report on Form 10-Q dated March 31, 2004.
(21) Previously filed as an exhibit to the Registrant's
Quarterly Report on Form 10-Q dated June 30, 2004.
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 31, 2005.
CHUGACH ELECTRIC ASSOCIATION, INC.
By: /s/ Evan J. Griffith
Evan J. Griffith, Chief Executive Officer
Date: March 31, 2005
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below on March 31, 2005, by the following persons on behalf of
the registrant in the capacities indicated:
/s/ Evan J. Griffith
Evan J. Griffith Chief Executive Officer
(Principal Executive Officer)
/s/ Lee D. Thibert
Lee D. Thibert General Manager, Distribution Division
/s/ Michael R. Cunningham
Michael R. Cunningham Chief Financial Officer
(Principal Financial Officer)
/s/ William R. Stewart
William R. Stewart Senior Vice President, Services Division
/s/ Bradley W. Evans
Bradley W. Evans General Manager, G&T Division
/s/ H. A. Boucher
H. A. Boucher Director & Chairman of the Board
/s/ Bruce Davison
Bruce Davison Director & Vice Chairman of the Board
/s/ Patricia B. Jasper
Patricia B. Jasper Director & Secretary of the Board
/s/ Jeffrey Lipscomb
Jeffrey Lipscomb Director & Treasurer of the Board
/s/ Samuel W. Cason
Samuel W. Cason Director
/s/ David Cottrell
David Cottrell Director
/s/ Christopher Birch
Christopher Birch Director
Supplemental information to be furnished with reports filed pursuant to Section
15(d) of the Act by registrants, which have not registered securities pursuant
to Section 12, of the Act:
Chugach has not made an Annual Report to securities holders for 2004 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.