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, 2003
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or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 33-42125
Chugach Electric Association, Inc.
(Exact name of registrant as specified in its charter)
Alaska 92-0014224
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5601 Minnesota Dr., Anchorage, Alaska 99518
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (907) 563-7494
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
-------------------------- ----------------------------------------
-------------------------- ----------------------------------------
Securities registered pursuant to Section 12(g) of the Act:
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(Title of class)
------------------------------------------------------------------------
(Title of class)
Indicate by check mark whether registrant (1) has filed reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
X Yes __ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Registration S-K (Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.
N/A
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act)
__Yes X No
State the aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the price at which the common equity
was last sold, or the average bid and asked price of such common equity, as of
the last business day of the registrant's most recently completed second fiscal
quarter.
N/A
CHUGACH ELECTRIC ASSOCIATION, INC.
2003 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
and Results of Operations 19
Item 7A - Quantitative and Qualitative Disclosures About Market Risk 38
Item 8 - Financial Statements and Supplementary Data 40
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 70
Item 9A - Disclosure Controls and Procedures 70
PART III
Item 10 - Directors and Executive Officers of the Registrant 71
Item 11 - Executive Compensation 74
Item 12 - Security Ownership of Certain Beneficial Owners and
Management 77
Item 13 - Certain Relationships and Related Transactions 77
Item 14 - Principal Accountant Fees and Services 77
PART IV
Item 15 - Exhibits, Financial Statement Schedules and Reports on
Form 8-K 78
SIGNATURES 91
CAUTION REGARDING FORWARD-LOOKING STATEMENTS
Statements in this report that do not relate to historical facts, including
statements relating to future plans, events or performance, are forward-looking
statements that involve risks and uncertainties. Actual results, events or
performance may differ materially. Readers are cautioned not to place undue
reliance on these forward-looking statements, that speak only as of the date of
this report and the accuracy of which is subject to inherent uncertainty.
Chugach Electric Association, Inc. (Chugach) undertakes no obligation to
publicly release any revisions to these forward-looking statements to reflect
events or circumstances that may occur after the date of this report or the
effect of those events or circumstances on any of the forward-looking statements
contained in this report, except as required by law.
PART I
Item 1 - Business
General
Chugach 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 Electric Association, Inc. 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
73,500 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 $.000392 per kWh of retail electricity sold. This charge is assessed to fund
the operations of the RCA. It is a pass-through and thus does not impact our
margins.
Our workforce consists of approximately 353 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, 2003, we had 62,009 retail members receiving service at
approximately 73,500 metered locations and three major wholesale customers. No
individual retail customer receives more than 5% of our power.
Our customers are billed per a tariff rate on a monthly basis for
electrical power consumed during the preceding period. Billing rates are
approved by the Regulatory Commission of Alaska (RCA) (see "Rate Regulation and
Rates" below).
Rates (derived on the basis of historic cost of service) are
established to generate revenues in excess of current period costs (net
operating margins and nonoperating margins) in any year and such excess is
designated on our Statements of Revenues, Expenses and Patronage Capital as
"assignable margins." Retained assignable margins are designated on our balance
sheet as "patronage capital" that is assigned to each member on the basis of
patronage.
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 2003, approximately 73% of our energy was generated at the Beluga
facility. We purchase up to 27.4 megawatts for our retail customers and up to
38.6 megawatts for our wholesale customers from the Bradley Lake Hydroelectric
Project. We also purchase approximately 40 megawatts from the Nikiski power
plant on the Kenai Peninsula. We operate 1,638 miles of distribution line and
402 miles of transmission line. For the year ended December 31, 2003, we sold
2.5 billion kilowatt hours (kWh) of electrical power.
Sales to Customers
The following table shows the energy sales to and electric revenues
from our retail, wholesale, and economy energy customers for the year ended
December 31, 2003:
Percent of Operating
MWh 2003 Revenues 2003 Sales
--- ------------- ----------
Direct retail sales:
Residential.................... 547,756 $61,712,958 34%
Commercial..................... 628,831 54,004,530 30%
------- ---------- ---
Total.......................... 1,176,587 115,717,488 64%
Wholesale sales:
MEA............................ 620,164 34,205,260 19%
HEA............................ 448,029 21,733,244 12%
Seward......................... 60,966 2,461,200 1%
------ --------- --
Total.......................... 1,129,159 58,399,704 32%
Economy energy sales(1) ............ 191,616 7,112,276 4%
------- ---------
Total sales to customers............ 2,497,362 181,229,468 100%
========= ====
Miscellaneous energy revenue 2,802,945
---------
Total energy revenues $184,032,413
============
(1) Economy sales were made to GVEA and AML&P.
Retail Customers
Service Territory
Our retail service area covers the populated areas of Anchorage (other
than downtown Anchorage) as well as remote mountain areas and villages. The
service area ranges from the northern Kenai Peninsula on the south, to Tyonek on
the west, to Whittier on the east and to the Glenn Highway on the north.
Customers
As of December 31, 2003, we had 62,009 members being served by
approximately 73,500 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 2003, our wholesale power contracts,
including the fuel component, produced $58.4 million in revenues, representing
32% of our revenues and 45% of our total kWh sales to customers.
MEA and HEA
We have two power sales contracts with Alaska Electric Generation &
Transmission Cooperative, Inc., (AEG&T): one for firm, all requirement sales to
MEA and one for firm, partial requirement sales to HEA. AEG&T is a generation
and transmission cooperative that was formed by MEA and HEA in the mid 1980's.
Under each of these contracts, we sell power to AEG&T, which resells the power
to MEA and HEA. MEA and HEA have recently indicated that they may be disbanding
or substantially changing their relationship with AEG&T but no changes to our
contracts have been made at this time. Under our contracts, each of MEA and HEA
is obligated to pay us for the power sold to AEG&T even if AEG&T does not pay.
Under the contract, MEA is obligated to purchase all of its electric
power and energy requirements from us. Contractually, MEA has the right, on
advance notice and subject to RCA approval, to convert to a net requirements
purchaser of power, and as such MEA would be obligated to buy its needed power
from us net of its power needs satisfied from any of its own or AEG&T's
resources. The notice period required for such conversion may be up to five
years, depending on which non-Chugach resources MEA proposes to use to satisfy
its power needs. MEA has not invoked this right at this time.
If MEA converts to a net requirements purchaser under the contract, MEA
cannot reduce its payment for power that it purchases from us below a certain
minimum amount. MEA will be required to pay demand charges based upon the
highest post-1985 historical coincident peak on the MEA system. Therefore, if
MEA converts to net-requirements service, we will continue to recover all or
substantially all of the fixed costs now assigned to it. Also, our revenues from
energy sales to MEA would partially decline in proportion to the reduction in
the energy sold, but this decline would be offset to an extent by savings in the
variable costs associated with energy production.
MEA also has the right, on seven years advance notice and subject to
RCA approval, to convert to a take-or-pay purchase of a fixed amount of power,
also subject to minimum payment requirements associated with prior purchases.
The MEA contract is in effect through December 31, 2014.
During the past several years, we have had numerous disputes and
engaged in substantial litigation with MEA regarding many aspects of our
contractual relationship with it. For a discussion of material pending
litigation between MEA and us, see "Legal Proceedings."
Our contract for the benefit of HEA obligates HEA (through AEG&T) to
take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per
year. The HEA contract includes limitations on the costs that may be included in
our rates charged to it. The HEA contract expires on January 1, 2014. HEA's
remaining resource requirements are provided by AEG&T's Nikiski cogeneration
facility and AEG&T's entitlement for power from the Bradley Lake hydroelectric
project for the benefit of HEA. In February 1999, we entered into a dispatch
agreement with AEG&T to operate the Nikiski unit as a Chugach system resource.
The agreement provides that, in addition to the energy that we already sell to
AEG&T and HEA, we will sell energy to AEG&T equal to HEA's residual energy
requirements less its allocated share of the Bradley Lake project, up to a
maximum of 320,000 MWh per year. A portion of the Nikiski unit output may be
dispatched for HEA needs in excess of the sum of our contract demand plus HEA's
share of energy from the Bradley Lake project. The dispatch agreement will
terminate in 2014 when our power supply contract for the benefit of HEA
terminates.
On 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, 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. Management does not expect a decline in revenue as a result of
this transfer.
Seward
We currently provide nearly all the power needs of the City of Seward.
In February 1998, we entered into a new power sales agreement with Seward that
allows us to interrupt service to Seward up to 12 times per year and thereby
reduces the demand charge by 1/3 (approximately $350,000 annually). This
agreement was originally set to expire September 11, 2001, but we negotiated an
amendment to the agreement that extended its term to January 31, 2006. The RCA
conditionally approved the extension on July 9, 2001. The RCA required an
amendment to the contract to include an option to re-negotiate the terms of the
contract if rates were adjusted by the general rate case we filed in July 2001.
Seward had three choices within sixty days of the final order. The choices were
to continue the contract using the rate methodology adopted in the case,
negotiate a new contract or give notice of termination effective twelve months
from the effective date of the final order of the RCA. On December 17, 2003,
Seward provided notice to Chugach of their election to continue with the
contract, as amended, under the new permanent rates established by final order
of the RCA in Docket No. U-01-108.
Economy Customers
Since 1988, we have sold economy (nonfirm) energy to Golden Valley
Electric Association (GVEA) under an agreement that expires in 2008. Under the
agreement, we use available generating capacity in excess of our own needs to
produce electric energy for sale to GVEA, which uses that energy to serve its
own loads in place of more expensive energy that it would otherwise generate
itself or purchase from other sources. We purchased gas from Marathon Oil
Company (Marathon) to produce energy for sale to GVEA, and we charge GVEA a rate
sufficient to recover the gas cost, the costs of incremental operations and
maintenance expense resulting from increased use of our generators for GVEA, and
an agreed-upon margin for each kWh sold.
In 2000, the RCA approved an amendment to our agreement with GVEA and a
settlement of an inter-utility dispute. As a result, the market for economy
energy sold to GVEA has now been divided into two parts. The larger part
continues to be governed by a contractual priority right under our agreement
with GVEA. Under this provision, if GVEA requires non-firm energy in sufficient
quantities, we have an opportunity to sell two-thirds of the first 450,000 MWh
and an additional 80% of the excess over 450,000 MWh of the non-firm energy that
GVEA purchases each year if we are capable of producing that energy. Under the
above provisions, non-firm sales to GVEA for the years 2003, 2002 and 2001 have
been 191,616 MWh, 125,462 MWh and 81,924 MWh, 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 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 downward from 1.35 to 1.30. Based on all the
adjustments stated in Order U-01-108(26), see "Management's Discussion and
Analysis - Results of Operations - Overview - Rate Regulation and Rates," for
the year ended December 31, 2003, our achieved TIER was calculated to be 1.27.
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. 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) 2004 2005 2006 2007 2008
---------- ---- ---- ---- ---- ----
Retail............ 1,193,000 1,211,000 1,228,000 1,240,000 1,254,000
Wholesale......... 1,178,000 1,204,000 1,230,000 1,244,000 1,244,000
Economy........... 173,000 165,000 165,000 165,000 165,000
Losses............ 143,670 146,171 148,352 150,006 151,239
Total.......... 2,687,670 2,726,171 2,771,352 2,799,006 2,814,239
========= ========= ========= ========= =========
Sales are expected to increase over the next five years principally due
to economic growth in the service sector. Our total energy requirements are
expected to grow at an average annual rate of 1.3% from 2004 to 2008, retail
sales at a rate of 1.3% and wholesale sales at a rate of 1.4%. 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 have 11.7 megawatts of capacity from the two
Eklutna Hydroelectric Project generating units that we jointly own with MEA and
AML&P. In addition to our own generation, we purchase power from the 126
megawatt Bradley Lake hydroelectric project owned by the Alaska Energy Authority
(AEA) through Alaska Industrial Development and Export Authority. The Bradley
Lake facility is operated by HEA and dispatched by us. The Beluga, Bernice Lake
and International facilities are all fueled by natural gas. We own our offices
and headquarters, located adjacent to IGT in Anchorage. We also lease warehouse
space for some generation, transmission and distribution inventory (including a
small amount of office space).
Generation Assets
We own the land and improvements comprising our generating facilities
at Beluga and International. 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 a major inspection in 2002 with combustion
inspections performed in 2003. Beluga Unit 5 received a hot gas path inspection
in 2002 with combustion inspections in 2003. The first major inspection of
Beluga Unit 6 was performed in 2003 since the unit was repowered in 2000. During
that inspection the first stage of blades and vanes designs were changed
resulting in a gain in power output. Beluga Unit 7 was repowered in 2001. A
combustion inspection was performed on Unit 7 during 2003 and its first major
inspection after the repower will take place in 2004. Beluga Unit 8, a steam
turbine, received a major inspection in 2002 and a routine annual inspection
took place in 2003.
The following matrix depicts nomenclature, run hours for 2003 and
percentages of contribution and other historical information for all Chugach
generation units.
Percent of
total Percent of
Commercial Operation Rating Run hours generation time
Facility Date Nomenclature (MW)(1) (2003) hours available
-------- ---- ------------ ------- ------ ----- ---------
Beluga Power
Plant (3)
1 1968 GE Frame 5 19.6 409.1 0.80 88.18
2 1968 GE Frame 5 19.6 473.8 0.93 95.84
3 1972 GE Frame 7 64.8 5,459.3 10.66 89.51
5 1975 GE Frame 7 68.7 6,113.5 11.94 94.18
6 1975 AP 11DM-EV 79.2 6,448.5 12.59 73.61
7 1978 AP 11DM-EV 80.1 8,123.1 15.87 92.73
8 1981 BBC DK021150(2) 53.0 8,000.6 15.63 91.33
-----
-----
Bernice Lake 385.0
Power Plant
2 1971 GE Frame 5 19.0 21.4 0.04 89.68
3 1978 GE Frame 5 26.0 2,146.6 4.19 97.08
4 1981 GE Frame 5 22.5 1,264.5 2.47 97.49
-----
-----
Cooper Lake 67.5
Hydroelectric
Plant
1 1960 BBC MV 230/10 9.6 6,178.0 12.07 95.85
2 1960 BBC MV 230/10 9.6 5,943.6 11.61 95.97
-----
-----
IGT Power Plant 19.2
1 1964 GE Frame 5 14.1 187.4 0.37 99.90
2 1965 GE Frame 5 14.1 406.3 0.79 91.37
3 1969 Westinghouse 191G 18.5 22.6 0.04 86.56
-----
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
System Total ----- 51,198.3 100.00
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.
Note: GE = General Electric, BB = Brown Boveri
Transmission and Distribution Assets
As of December 31, 2003, our transmission and distribution assets
included 39 substations and 402 miles of transmission lines, 928 miles of
overhead distribution lines and 710 miles of underground distribution line. We
own the land on which 20 of our substations are located and a portion of the
right-of-way connecting our Beluga plant to Anchorage. As part of our 1997
acquisition of 30% of the Eklutna facility, we also acquired a partial interest
in two substations and additional transmission facilities.
Many substations and a substantial number of our transmission and
distribution rights-of-way are the subject of federal or state permits and
licenses. Under a federal license and a permit from the United States Forest
Service, we operate the Quartz Creek transmission substation, substations at
Hope, Summit Lake and Daves Creek, and transmission lines over all federal lands
between Cooper Lake on the Kenai Peninsula and Anchorage. Long-term permits from
the Alaska Division of Lands and the Alaska Railroad Corporation govern much of
the rest of our transmission system outside the Anchorage area. Within the
Anchorage area, we operate our University substation and several major
transmission lines pursuant to long-term rights-of-way grants from the U.S.
Department of the Interior, Bureau of Land Management, and transmission and
distribution lines have been constructed across privately owned lands via
easements across public rights-of-way and waterways pursuant to authority
granted by the appropriate governmental entity.
Title
Under the Amended and Restated Indenture, all of Chugach's bonds are
general unsecured and unsubordinated obligations. Chugach is prohibited from
creating or permitting to exist any mortgage, lien, pledge, security interest or
encumbrance on our properties and assets (other than those arising by operation
of law) to secure the repayment of borrowed money or the obligation to pay the
deferred purchase price of property unless we equally and ratably secure all
bonds subject to the Amended and Restated Indenture, except that we may incur
secured indebtedness in an amount not to exceed $5 million or enter into sale
and leaseback or similar agreements.
Many of our properties are burdened by easements, plat restrictions,
mineral reservation, water rights and similar title exceptions common to the
area or customarily reserved in conveyances from federal or state governmental
entities, and by additional minor title encumbrances and defects. We do not
believe that any of these title defects will materially impair the use of our
properties in the operation of our business.
Under the Alaska Electric and Telephone Cooperative Act, we possess the
power of eminent domain for the purpose and in the manner provided by Alaska
condemnation laws for acquiring private property for public use.
Other Property
Bradley Lake. We are a participant in the Bradley Lake hydroelectric
project, which is a 126 megawatt rated capacity hydroelectric facility near
Homer on the southern end of the Kenai Peninsula that was placed into service in
September 1991. The project is nominally scheduled at 90 megawatts to minimize
losses and insure system stability. We have a 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), GVEA, Seward and
us). The participating utilities have entered into take-or-pay power sales
agreements under which AEA has sold percentage shares of the project capacity
and the utilities have agreed to pay a like percentage of annual costs of the
project (including ownership, operation and maintenance costs, debt-service
costs and amounts required to maintain established reserves). We also provide
transmission and related services as a wheeling agent (one who dispatches and
transmits power of third parties over its own system) for all of the
participants in the Bradley Lake project.
The length of our Bradley Lake power sales agreement is fifty years
from the date of commercial operation of the facility (September, 1991) or when
the revenue bond principal is repaid, whichever is the longer. 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 $4.1 million. We believe that so
long as this project produces power taken by us for our use that this expense
will be recoverable through the fuel surcharge mechanism. The share of Bradley
Lake indebtedness for which we are responsible is approximately $44 million.
Upon the default of a participant, and subject to certain other conditions, AEA
is entitled to increase each participant's share of costs and output pro rata,
to the extent necessary to compensate for the failure of the defaulting
participant to pay its share, provided that no participant's percentage share is
increased by more than 25%.
We negotiated with AEG&T a scheduling agreement whereby we schedule
HEA's share of the Bradley Lake project through AEG&T for the benefit of the
Railbelt electric system. AEG&T continues to pay its Bradley Lake project costs
and receives credit for the Bradley Lake energy generated for HEA. We pay a
fixed annual fee of $112,000 to AEG&T for these scheduling rights. This
agreement allows us to improve the efficiency of our generating resources
through better hydrothermal coordination.
Eklutna. We purchased a 30% undivided interest in the Eklutna
Hydroelectric Project from the federal government in 1997. MEA also owns 17% of
the Eklutna Hydroelectric Project. The power MEA purchases from the Eklutna
Hydroelectric Project is pooled with our purchases and sold back to MEA to be
used in meeting MEA's overall power requirements. AML&P owns the remaining 53%
undivided interest in the Eklutna Hydroelectric Project.
Fuel Supply
For 2003, 84% of our power was generated from gas, and 97% 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 Oil Company
(Marathon). ConocoPhillips, AML&P and ChevronTexaco each own one-third of the
gas produced from the Beluga River Field and in 2003 provided approximately
equal shares of the Beluga gas. We have approximately 310 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 23.5 BCF of
natural gas per year for firm service. We believe that this usage will increase
approximately 0.5 BCF per year and estimate that our contract gas will last 10
to 15 years. 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) ($2.3814
per thousand cubic feet (MCF) on January 1, 2004), 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) ($2.9768 per MCF on January
1, 2004), 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 prices of West
Texas Intermediate Crude Oil (a benchmark of the Light Sweet Crude Oil Futures
Index), the Producer Price Index for natural gas, and the Consumer Price Index
for heating fuel oil. The price on January 1, 2004, exclusive of taxes, was
$2.7062 per MCF.
Under the terms of the Marathon contract, Marathon generally provides
the primary supply of gas required for sales to GVEA, all of our requirements at
Bernice Lake, International and Nikiski and 40% of the requirements at Beluga,
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. We hold a reservation to receive our
gas requirements at IGT from ENSTAR under a tariff approved by the RCA in the
event that the transportation agreement is subsequently canceled. ENSTAR is
obligated to supply all of the gas we require at a price approved by the RCA.
There is a monthly minimum bill of $10,465 but no requirement to actually use
any gas at IGT.
Environmental Matters
General
Chugach's operations are subject to certain federal, state and
local environmental laws and regulations, which seek to limit air, water and
other pollution and regulate hazardous or toxic waste disposal. While we
monitor these laws and regulations to ensure compliance, they frequently
change and often become more restrictive. When this occurs, the costs of our
compliance generally increase.
We include costs associated with environmental compliance in both
our operating and capital budgets. We accrue for costs associated with
environmental remediation obligations when those costs are probable and
reasonably estimable. We do not anticipate that environmental related
expenditures will have a material effect on our results of operations or
financial condition. We cannot, however, predict the nature, extent or cost
of new laws or regulations relating to environmental matters.
The Clean Air Act and Environmental Protection Agency (EPA)
regulations under the act (the "Clean Air Act") establish ambient air
quality standards and limit the emission of many air pollutants. Some Clean
Air Act programs that regulate electric utilities, notably the Title IV
"acid rain" requirements, do not apply to facilities located in Alaska. The
EPA's anticipated regulations to limit mercury emissions from fossil-fired
steam-electric generating facilities, are not expected to materially impact
Chugach because our thermal power plants burn exclusively natural gas.
New Clean Air Act regulations impacting electric utilities may
result from future events or may result from new regulatory programs that
may be established to address problems such as global warming. While we
cannot predict whether any new regulation would occur or its limitation, it
is possible that new laws or regulations could increase our capital and
operating costs. We have obtained or applied for all Clean Air Act permits
currently required for the operation of our generating facilities, and we
are not aware of any future requirements that will materially impact our
financial condition.
Chugach is subject to numerous other environmental statutes
including the Clean Water Act, the Resource Conservation and Recovery Act,
the Toxic Substances Control Act, the Endangered Species Act, and the
Comprehensive Environmental Response, Compensation and Liability Act and to
the regulations implementing these statutes. We do not believe that
compliance with these statutes and regulations to date has had a material
impact on our financial condition or results of operation. However, new laws
or regulations, implementation of final regulations or changes in or new
interpretations of these laws or regulations could result in significant
additional capital or operating expenses.
Cooper Lake
Chugach discovered polychlorinated biphenyls (PCBs) in paint,
caulk and grease at the Cooper Lake Hydroelectric plant during initial
phases of a turbine overhaul. A FERC approved plan, prepared in
consultation with the Environmental Protection Agency (EPA), was
implemented to remediate the PCBs in the plant. As a condition of its
approval of the license amendment for the overhaul project, FERC required
Chugach to also investigate the presence of PCBs in Kenai Lake. A
sampling plan was developed by Chugach in consultation with state and
federal agencies and approved by FERC. In 2000, Chugach sampled sediments
and fish collected from Kenai Lake and other waters. While low levels of
PCBs were found in some sediment samples taken near the plant, no pathway
from sediment to fish was established. While the levels of PCBs in fish
from Kenai Lake were similar to levels found in fish from other lakes
within the region, Chugach conducted additional sampling and analysis of
fish in Kenai Lake and other waters and filed Chugach's final report
dated April 1, 2002, with FERC, which analyzed the results of the
sampling. Based on these analyses, Chugach concluded that no further PCB
sampling and analysis in Kenai Lake was necessary. In a letter dated June
13, 2002, FERC informed Chugach that its review of the report supported
Chugach's conclusions and agreed Chugach was not required to conduct
further PCB sampling and analysis in Kenai Lake. In its recent order in
Chugach's general rate case, Order U-01-108(26), the RCA permitted the
costs associated with the overhaul and the PCB remediation to be
recovered through rates. Consequently, management believes the costs of
the PCB remediation and studies will have no material impact on Chugach's
financial condition or results of operations.
Item 3 - Legal Proceedings
Matanuska Electric Association, Inc., v. Chugach Electric Association, Inc.,
Superior Court Case No. 3AN-99-8152 Civil
This action is a claim for a breach of the Tripartite Agreement,
which is the contract governing the parties' relationship for a 25-year
period from 1989 through 2014 and governing our sale of power to MEA during
that time. MEA asserted we breached that contract by failing to provide
information, by failing to properly manage our long-term debt, and by
failing to bring our base rate action to a Joint Committee before presenting
it to the RCA. The committee is defined in the power sales contract and
consists of one MEA and two Chugach board members. All of MEA's claims have
been dismissed. On April 29, 2002, MEA appealed the Superior Court's
decisions relating to our financial management and our failure to bring our
base rate action to the joint committee before filing with the RCA to the
Alaska Supreme Court. We cross-appealed the Superior Court's decision not to
dismiss the financial management claim on jurisdictional and res judicata
grounds. Oral argument was heard by the Supreme Court on April 15, 2003.
Management is uncertain as to the outcome and expects a decision within
twelve months.
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 2003 2002 2001 2000 1999
---- ---- ---- ---- ----
Plant, net:
In service $450,888,424 $450,480,385 $452,964,686 $427,127,258 $398,544,496
Construction work in
Progress 16,560,438 20,224,302 28,887,008 42,027,617 47,257,296
---------- ---------- ---------- ---------- ----------
Electric plant, net 467,448,862 470,704,687 481,851,694 469,154,875 445,801,792
Other assets 91,342,641 99,510,187 93,429,493 70,591,105 72,553,745
---------- ---------- ---------- ---------- ----------
Total assets $558,791,503 $570,214,874 $575,281,187 $539,745,980 $518,355,537
============ ============ ============ ============ ============
Capitalization:
Long-term debt 384,289,179 389,834,179 364,310,000 312,219,945 337,150,295
Equities and margins 134,216,122 127,477,895 131,808,706 128,815,340 122,524,645
----------- ----------- ----------- ----------- -----------
Total capitalization $518,505,301 $517,312,074 $496,118,706 $441,035,285 $459,674,940
============ ============ ============ ============ ============
Summary Operations Data
Operating revenues $184,032,413 $171,944,918 $178,595,214 $158,541,114 $142,644,327
Operating expenses 156,003,029 149,369,936 147,496,721 126,430,273 110,456,886
Interest expense 22,860,828 26,230,825 28,353,487 26,158,769 25,228,001
Amortization of gain on
Refinancing 0 188,082 1,123,973 1,440,479 1,092,620
- ------- --------- --------- ---------
Net operating margins 5,168,556 (3,467,761) 3,868,979 7,392,551 8,052,060
Nonoperating margins 1,084,564 1,451,611 1,670,157 2,287,227 1,615,374
--------- --------- --------- --------- ---------
Assignable margins $6,253,120 $(2,016,150) $5,539,136 $9,679,778 $9,667,434
========== ============ ========== ========== ==========
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
---- ----
2003 1.27
2002 0.92*
2001 1.20
2000 1.39
1999 1.40
*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.
Base rates include a fuel and purchased power component, which consist primarily
of costs other than fuel and purchased power costs. "Fuel surcharge" rates take
into account the rise and fall of fuel and purchased power costs and ensure
collection of fuel and purchased power costs above the base component included
in the base energy rate. The RCA approves the amounts paid by our wholesale and
retail customers under base rates and approves the quarterly fuel surcharge
filing authorizing rate changes in the fuel surcharge calculations. 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.
As required by an Order from the RCA we filed a general rate case on
July 10, 2001, based on the 2000 test year expenses. We requested a permanent
base rate increase of 6.5%, and an interim base rate increase of 4.0%. On
September 5, 2001, the RCA granted a 1.6% interim increase effective September
14, 2001. Chugach filed a petition for reconsideration and on October 25, 2001,
the RCA approved an interim base rate increase of 3.97%. The additional rate
increase was implemented on November 1, 2001. The interim rate increase was
based on a normalized (adjusted for recurring expenses) test year and a system
ratemaking TIER of 1.35. In this filing for permanent rates, Chugach proposed
that margins be calculated using a return on rate base methodology rather than
the TIER methodology previously used.
As anticipated in Chugach's July 2001 original filing, on April 15,
2002, Chugach submitted a filing with the RCA to update certain known and
measurable costs and savings that had occurred outside the 2000 Test Year. In
the updated filing, Chugach reduced its base rate increase request from 6.5% to
5.7%, or approximately $0.9 million in the revenue requirement on a system
basis. The revised filing also reflected an increase in depreciation expense of
approximately $1.5 million due to the completion of the Beluga Unit 7
re-powering project and a reduction in annualized interest expense, due to
Chugach's recent refinancing efforts, of $2.4 million. In that revised filing,
Chugach continued to request $11.9 million in margins. As a result of reduced
interest costs, this would have yielded an equivalent system TIER of 1.47.
Three intervenors filed pre-filed testimony with the RCA in July 2002
opposing various aspects of Chugach's proposal. Chugach filed its reply
testimony with the RCA on October 1, 2002. The hearing to resolve the
outstanding issues associated with the 2000 test year rate case took place in
November and December of 2002, concluding on December 13, 2002.
Between February 6, 2003 and January 27, 2004, the RCA issued Order
Nos. 26 through 38 addressing various components of Chugach's rate case. The
orders that significantly impact Chugach are discussed below.
Docket U-01-108, Order No. 26
On February 6, 2003, Chugach received Order U-01-108(26) from the RCA.
Order 26 resolved several issues in Chugach's favor:
o The RCA rejected intervenor mismanagement allegations
regarding re-powering of Beluga Units 6, 7 and Cooper Lake
Power Plant (CLPP)overhaul and PCB remediation.
o The RCA accepted Chugach's proposal to amortize the cost of
Chugach's "rate lock" and did not question other refinancing
activities.
o The RCA approved the 1999 depreciation study, in part, and
allowed implementation of remaining life depreciation
methodology.
o The RCA approved recovery of rate lock and CLPP PCB
remediation expenses.
Order 26 contained several adjustments not in Chugach's favor:
o The RCA required Chugach to continue using TIER in calculating
return levels instead of converting to a return on rate-base
methodology.
o The RCA adjusted Chugach's system overall TIER downwards from
1.35 to 1.30, a difference of approximately $1.2 million in
margins based on the 2000 test year. The Order will have
similar impacts in subsequent years. As Chugach had requested
that its permanent rates in this case be established with an
effective TIER of 1.47, the 1.30 TIER reduced margins by
approximately $4 million from those requested in our filing.
o The RCA required Chugach to treat Allowance for Funds Used
During Construction/Interest During Construction (AFUDC / IDC)
as a reduction to long-term interest expense, which reduces
the revenue requirement by approximately $1.2 million,
excluding TIER. With the required AFUDC/IDC adjustment alone,
Chugach's effective TIER would be below a 1.30.
o The RCA required a 1.8 percentage point interest rate
reduction (from 3.8% to 2%) on Chugach's $60.0 million of
variable debt, which would equate to a revenue requirement
reduction of approximately $1.1 million, excluding TIER.
o Chugach's overall Depreciation Study was approved, although
the RCA did require approximately $0.7 million in downward
adjustments, primarily related to Bernice Lake Units 2 - 4 and
Chugach's North Submarine Cable field. This reduction in the
revenue requirement will match Chugach's reduction in
depreciation expense, resulting in a net effect of zero to
margins in subsequent years.
Order 26 required a refund of revenues collected in 2001 of
approximately $1.1 million and in revenues collected in 2002 of approximately
$6.0 million, which resulted in a net operating loss of $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 Amended and Restated Indenture, the
CoBank Master Loan Agreement and the MBIA Insurance Corporation's (MBIA)
Reimbursement and Indemnity Agreement.
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,
our motion for stay. Chugach filed the Petition for Reconsideration with the RCA
on February 28, 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. The
Amended and Restated Indenture also requires Chugach, subject to any necessary
regulatory approval, to establish and collect rates reasonably expected to yield
margins for interest equal to at least 1.10 times total interest expense. If
there occurs any material change in the circumstances contemplated at the time
rates were most recently reviewed, the Amended and Restated Indenture requires
Chugach to seek appropriate 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, subject to any necessary regulatory approval
or determination.
Docket U-01-108, Order No. 30
On April 15, 2003, the RCA issued Order No. 30 in Docket U-01-108,
significantly revising its earlier ruling by:
o Reversing its AFUDC/IDC offset decision and agreeing with
Chugach that the offset of AFUDC and IDC against long-term
interest expense in the test year is not appropriate. Language
in Order 30 may limit its ruling to projects commenced and
concluded within the test year.
o Allowing most of the legal expenses reduced or amortized from
the revenue requirement to be added back.
o Establishing a normalized interest rate of 3.8% on our $60
million in variable rate debt.
o Clarifying that it intended to set a floating TIER of 1.64 for
Distribution.
o Clarifying, as requested by Chugach, that the refund cannot go
below the "floor" of the rates that were in place prior to
Chugach's interim increase.
o Clarifying that interest expense should be allocated based on
net plant.
o Authorizing Chugach to use the higher interest rate existing
in January and February of 2002 (before the March refinancing
reduced interest expense) in calculating any refunds.
In Order No. 30, the RCA also:
o Declined to change its ruling continuing the split TIER.
o Declined to change its ruling reducing overall TIER to 1.30
and reducing Generation and Transmission (G&T) TIER to 1.10.
o Declined to change its ruling that rate case costs cannot be
amortized and recovered in rates.
On April 28, 2003, Chugach submitted a revised revenue requirement and
cost of service study in compliance with RCA Order No. 30. The revised filing
reflected adjustments related to the ratemaking treatment of AFUDC/IDC, interest
expense, and legal expense, which had the impact of increasing Chugach's revenue
requirement by $3.1 million.
Docket U-01-108, Order No. 33
On August 26, 2003, the RCA issued Order No. 33 and accepted Chugach's
April 28, 2003 compliance filing, in part. The RCA re-reversed its earlier
decision on the ratemaking treatment of AFUDC/IDC and required Chugach to comply
with the RCA's original ruling contained in Order No. 26 that reduced the
recovery of long-term interest expense by $1.2 million associated with
AFUDC/IDC.
On September 8, 2003, Chugach submitted its compliance filing to Order
No. 33 to reflect the AFUDC/IDC adjustment.
Docket U-01-108, Electronic Ruling
On November 7, 2003, the RCA issued an electronic ruling approving
Chugach's September 8 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.
Payment of Refunds
Chugach filed timely appeals of RCA Orders 26, 30 and 33. Initially,
Chugach obtained a stay of the Commission's orders, pending the outcome of the
appeal. After receiving the results of Order 33, however, Chugach determined
that removal of the stay on implementation of rates would increase Chugach
revenues by approximately $0.7 million on an annual basis and Chugach, in a
stipulated motion, asked the Court to remove the stay.
On November 10, 2003, Chugach issued refunds in the following amounts,
pursuant to Superior Court Order dated October 31, 2003, for demand and energy
usage between September 2001 and September 2003:
HEA $1,762,774
MEA $2,901,290
Seward $ 103,307
Chugach issued additional refund amounts totaling $70,894 to HEA and
$162,015 to MEA on December 29, 2003, for refund adjustments related to
Chugach's pre-refinancing activity that took place in February 2002.
Additional payments will be made to reflect interest on the refund
amounts. The RCA has not yet determined what interest rate will be applied.
Customers in Chugach's Small General Service rate class may also
receive a refund. Chugach expects that approximately 2,100 Small General Service
customers will receive refunds for electric service provided between January 31,
2003, and November 10, 2003. In Order No. 38, the RCA ruled that interest on
Small General Service refunds would be applied at an annual rate of 3.034
percent. Chugach expects the refund amount to the Small General Service class
will total approximately $0.6 million, including interest. Chugach expects this
refund to be completed by mid-April, 2004.
Chugach filed timely appeals of RCA Orders 26, 30 and 33. 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 offset for Interest During Construction 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.
Chugach's wholesale customer, MEA, also appealed the RCA's orders. In
its Appellant's brief, MEA confined itself to the argument 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.
Prior to 2001, our base rates to our retail customers had not increased
since 1994. As part of a settlement of disputes over rate adjustments with our
wholesale customers (the "Settlement Agreement"), we agreed that our base rate
for wholesale customers would not exceed 1995 levels at least through 1999 and
could be reduced if those rates provide returns significantly higher than those
specified in the settlement. As discussed below, we have granted refunds for
rates based on our 1996 costs. The RCA issued an order on February 27, 2001,
that no rate reduction or refunds were required based on our 1997 test year
costs. According to an order issued by the RCA on March 15, 2002, no rate
reduction or refunds were required based on our 1998 test year costs. Parties
had until April 1, 2002, to file a request for reconsideration and until April
15, 2002, to file an appeal. Neither were filed by any party regarding this
order. No additional test years remain to be reviewed under the Settlement
Agreement. Our base rate changes, excluding fuel surcharges, for retail and
wholesale classes for the years 2001 through 2003 were as follows:
Rate Class * 2003 2002 2001
---------- ---- ---- ----
Retail 0.24% 0.00% 3.97%
Wholesale:
HEA (10.9%) 0.00% 3.97%
MEA (12.4%) 0.00% 3.97%
SES (9.9%) 0.00% 0.00%
* Rate changes shown are based on percent changes as applied to demand
and energy rate levels. The 2001 increase of 3.97 percent was applied
on an interim and refundable basis to all classes except Small General
Service, Lighting and Seward Electric System.
Base rate changes in 2001 and 2003 were associated with Chugach's 2000
test period general rate case.
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.
The RCA ordered refunds of approximately $1.2 million because of
alleged over-collection of fuel surcharges in 1995, 1996 and 1997. We appealed
that finding to the Superior Court, which overturned it. MEA appealed that
decision to the Alaska Supreme Court and the RCA filed an amicus brief generally
supporting the MEA position. In a decision issued on November 15, 2002, the
Alaska Supreme Court affirmed the decision of the Superior Court. Chugach is no
longer required to issue refunds associated with fuel surcharge.
Year ended December 31, 2003, compared to the years ended December 31,
2002, and 2001
Margins
Our margins for the years ended December 31 were as follows:
2003 2002 2001
---- ---- ----
Net Operating Margins $ 5,168,556 $(3,467,761) $3,868,979
Nonoperating Margins $ 1,084,564 $ 1,451,611 $1,670,157
----------- ---------- ----------
Assignable Margins $ 6,253,120 $(2,016,150) $5,539,136
=========== ============ ==========
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. The decrease in assignable margins in 2002 of $7.6
million, or 136%, was due to the provision for rate refunds Chugach was required
to record as a result of RCA Order U-01-108(26).
Nonoperating margins include interest income, allowance for funds used
during construction, capital credits and patronage capital allocations.
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. Nonoperating margins decreased in 2002 from 2001 by $219,000, or
13%, due to the same reasons in 2003.
Revenues
Operating revenues include sales of electric energy to retail,
wholesale and economy energy customers and other miscellaneous revenues. 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. In
2002, operating revenues were $6.7 million, or 4%, lower than in 2001 due to a
$7.1 million provision for rate refund we recorded in 2002, calculated based on
the requirements set forth in RCA Order U-01-108(26). In addition, recoverable
fuel and purchased power expenses were lower in 2002 due to lower fuel prices.
The major components of our operating revenue for the year ended December 31
were as follows:
2003 2002 2001
---- ---- ----
Retail $115,717,488 $110,082,014 $112,026,122
Wholesale
HEA 21,733,244 22,035,973 24,260,072
MEA 34,205,260 30,018,227 33,706,678
Seward 2,461,200 2,709,752 2,816,970
Economy energy 7,112,276 4,567,179 3,354,719
Other 2,802,945 2,531,773 2,430,653
--------- --------- ---------
Total revenue $184,032,413 $171,944,918 $178,595,214
============ ============ ============
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 2003, 2002, and 2001,
economy sales to GVEA constituted approximately 4.0%, 2.7%, and 1.9%,
respectively, of our sales revenues. The increase in economy sales in 2003 from
2002 was due to GVEA maintenance schedule as well as it's higher fuel prices
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 2002 from
2001 was also due to GVEA's higher fuel prices.
Expenses
The major components of our operating expenses for the years ended
December 31 were as follows:
2003 2002 2001
---- ---- ----
Fuel $46,667,262 $46,822,943 $56,130,437
Other power production 13,961,565 13,500,103 12,397,465
Purchased power 18,244,921 18,750,936 14,717,318
Transmission 4,511,002 3,930,902 3,545,707
Distribution 10,866,251 10,869,335 10,417,736
Consumer accounts 5,589,788 5,594,572 5,121,394
Sales expense 0 0 495,523
Administrative, general and other 26,370,189 22,251,895 19,574,476
Depreciation 27,792,051 27,649,250 25,096,665
---------- ---------- ----------
Total operating expenses $156,003,029 $149,369,936 $147,496,721
============ ============ ============
Fuel
Fuel expense did not vary materially in 2003 from 2002. Fuel expense
decreased by $9.3 million, or 17%, in 2002 from 2001 due to lower fuel prices,
as well as lower volume purchases in 2002. Other power production expense did
not vary materially in 2003 from 2002.
Other Power Production
Other power production expense increased in 2002 from 2001 by $1.1
million, or 9%, due primarily to scheduled maintenance and inspections on
multiple units at Beluga and Bernice Lake.
Purchased Power
Purchased power costs did not vary materially in 2003 from 2002.
Purchased power costs increased by $4.0 million, or 27%, from 2001 to 2002 due
to the full-year impact of the new contract with AEG&T/HEA regarding Nikiski
Unit 1 and also a slight increase in the cost of power from Bradley Lake due to
operation and maintenance activities.
Transmission
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. Transmission expense increased in 2002 from 2001 by $385
thousand, or 11%, due to an increase in patrolling of the 138kV and 230kV lines,
bird nest removals and supporting rod replacements.
Distribution
Distribution expense did not vary materially in 2003 from 2002.
Distribution expense increased in 2002 from 2001 by $452 thousand, or 4%, due to
an increase in trouble calls relating to outages and damage claims. In addition,
expenses in 2002 were higher due to an increase in the number of locates
associated with an increase in local construction activity. Distribution
substation maintenance also increased due to problems discovered while utilizing
new predictive maintenance technology at multiple substations.
Consumer Accounts
Consumer accounts expense did not vary materially in 2003 from 2002.
Consumer accounts expense increased by $473 thousand, or 9%, from 2001 to 2002,
due to increased costs associated with billing and remittance processing as well
as increased bank and credit card fees. There was also a shift in the activities
of the Marketing Department from sales to customer information activities.
Sales
There was no sales expense in 2003. Sales expense decreased in 2002
from 2001 by $496 thousand, or 100%, due to the elimination of the Marketing
Department in 2002.
Administrative, General and Other
Administrative, general and other expenses increased by $4.1 million,
or 18.5%, 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. Administrative, general and other
expenses increased by $2.7 million, or 14% in 2002 from 2001, due to increased
consulting and outside counsel expenses related to the 2000 Test Year rate case.
In addition, a liability for our National Rural Electric Cooperative Association
(NRECA), past service cost adjustment was expensed in 2002. Insurance costs
recorded in 2002 were also higher than in 2001.
Depreciation
We use remaining life rates set forth in the most recently approved
depreciation study. Depreciation expense did not vary materially in 2003 from
2002. Depreciation expense increased in 2002 from 2001 by $2.6 million, or 10%,
due to an increase in capitalized plant, as well as the implementation of new
depreciation rates, effective January 1, 2002, as a result of RCA Order
U-01-108(26).
Interest
Interest on long-term obligations decreased $3.1 million, or 12% in
2003 from 2002, due to lower interest rates. Interest on long-term obligations
decreased by $967 thousand, or 4% in 2002 from 2001, due to the refinancing
completed in February 2002 and lower interest rates. This decrease was slightly
offset by the write-off of the gain on the 1991 refinanced debt against the
premium paid to refinance, as well as the associated transaction costs.
Interest on short-term borrowing decreased $137 thousand, or 46% in
2003 from 2002, due to a decrease in short-term borrowing, as well as decreased
interest rates. Interest on short-term obligations decreased by $866 thousand,
or 74% in 2002 from 2001, due to the same reasons as in 2003. Interest charged
to construction did not vary materially in 2003 from 2002.
Interest charged to construction decreased in 2002 from 2001 by $646
thousand, or 61%, due to a lower average balance in Construction Work in
Progress and lower interest rates. 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:
2003 2002 2001
---- ---- ----
Patronage capital at beginning of year $120,148,502 $125,184,374 $122,925,253
Retirement of capital credits
and estate payments (60,208) (3,019,722) (3,280,015)
Assignable margins 6,253,120 (2,016,150) 5,539,136
--------- ----------- ---------
Patronage capital at end of year 126,341,413 120,148,502 125,184,374
Other equity 7,874,709 7,329,393 6,624,332
--------- --------- ---------
Total equity at end of year $134,216,122 $127,477,895 $131,808,706
============ ============ ============
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. 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. At December 31, 2002, we
retired all retail capital credits attributable to margins earned in periods
prior to and including 1985 retail capital credits. Prior to 2000, wholesale
capital credits had been retired on a 10-year cycle pursuant to an approved
capital credit retirement program, which 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 (x) five percent (5%) of our aggregate
equities and margins as of the end of the immediately preceding fiscal year or
(y) fifty percent (50%) of the prior fiscal year's margins.
We also retire our patronage credits through annual payments to our
members. The table below sets forth a five-year summary of anticipated capital
credit retirements:
Year Ending Total
2004 $3,000,000
2005 3,000,000
2006 2,600,000
2007 2,900,000
2008 3,500,000
Sale of a Segment
As of March 6, 2001, with an effective date of March 20, 2001, Chugach
sold the majority of its internet service provider assets related to dial-up
services (excluding DSL services) to General Communication Incorporated. The
aggregate purchase price was $759,049 at closing, plus an additional amount of
$70,075, which was based on number of subscriber accounts retained during the
ninety-day transition period following closing. These transactions resulted in a
loss of $258,073.
Changes in Financial Condition
Assets
Total assets decreased by $11.4 million, or 2%, from December 31, 2002,
to December 31, 2003. The net decrease was due to a $3.3 million decrease in net
utility plant, caused by an increase in accumulated depreciation due to plant
capitalized in prior periods. The decrease was also attributed to a $7.6 million
decrease in accounts receivable due to several large billings to the State of
Alaska for completed projects in 2002. There was also a decrease of $4.5 million
in deferred charges caused by the write-off of several studies, as well as a
$1.9 million decrease in materials and supplies caused by the use of generation
inventory items purchased in 2002 for scheduled maintenance projects in 2003.
These decreases were offset by an increase of $3.9 million in cash and cash
equivalents caused by the collection of the State of Alaska billings discussed
above and an increase of $2.0 million in fuel cost recovery caused by the
under-collection of the prior quarter's fuel cost.
Liabilities and Equities
Changes in total liabilities include a $6.1 million decrease in
short-term obligations caused by the collection of outstanding accounts
receivable used to pay off the line of credit. There was also a $6.4 million
decrease in provision for rate refund caused by an adjustment calculated by RCA
Order 30. (See "Management's Discussion and Analysis - Results of Operations -
Rate Regulation and Rates.") Long-term obligations decreased by $5.5 million due
to continued principal payments on our long-term debt. Other current liabilities
also decreased by $1.2 million due to the payment of purchased power invoices by
year-end and the decrease in patronage capital payable caused by patronage
capital not being returned in 2003. There was also a $500 thousand decrease in
deferred credits caused by a decrease in customer advances on line extensions
and a $364 thousand decrease in fuel cost payable due to our under-collection of
the prior quarter's fuel cost creating a fuel cost receivable instead of a
payable at year-end. These decreases were offset by an increase of $1.9 million
in fuel expense due to higher fuel prices.
Changes in equities include a $6.7 million increase in patronage
capital due primarily to margins earned and patronage capital not being returned
in 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, 2003:
Contractual cash obligations: (In thousands)
Payments Due By Period
Total 2004 2005-2006 2007-2008 Thereafter
Long-term debt $389,834 $5,545 $22,257 $18,969 $343,063
Short-term debt* 0 0 0 0 0
- - - - -
Total $389,834 $5,545 $22,257 $18,969 $343,063
Commercial Commitments: (In thousands)
Amount of Commitment
Expiration Per Period
Total 2003 2004-2005 2006-2007 Thereafter
Lines of credit-available * $70 $70 $0 $0 $0
*At December 31, 2003, Chugach had $70 million in lines of credit available with
various financial institutions, which fund capital requirements. At December 31,
2003, there was no outstanding balance on the lines of credit, therefore, the
available borrowing capacity under these lines of credit was $70 million.
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 NRUCFC,
which was renewed for a five-year term on October 15, 2002, and a $20 million
line of credit with CoBank, which expires December 31, 2004, subject to renewal
at the discretion of the parties. At December 31, 2003, there was no outstanding
balance with CFC or CoBank.
On April 17, 2001, we issued $150 million of 2001 Series A Bond, for
the purpose of retiring indebtedness outstanding under existing lines of
credit and outstanding bonds, for capital expenditures and for general
working capital. The lines of credit had an aggregate outstanding principal
balance of $55 million, as of April 17, 2001, were renewable annually and
bore interest at variable annual rates ranging from 7.55% to 7.80% at April
17, 2001. The variable-rate bonds retired had an aggregate outstanding
principal balance of $72.5 million, as of April 17, 2001, would have matured
in 2002 and bore interest at a variable rate that was 7.55% on April 17,
2001. The 2001 Series A Bond will mature on March 15, 2011, and bears
interest at 6.55% per annum. Interest is payable semi-annually on March 15
and September 15 of each year commencing on September 15, 2001.
On February 1, 2002, we issued $120 million of 2002 Series A Bond and
$60 million of 2002 Series B Bond for the purpose of redeeming $149.3
million in principal amount of the 1991 Series A Bond due 2022, to pay the
redemption premium on the 1991 Series A Bond due 2022 in the amount of $13.6
million and for general working capital. The 2002 Series A Bond will mature
on February 1, 2012, and bears interest at 6.20% per annum. Interest is
payable semi-annually on February 1 and August 1 of each year commencing on
August 1, 2002. Chugach may not redeem the 2002 Series A Bond prior to
maturity.
The 2002 Series B Bond (the "Auction Rate Bond") will mature on
February 1, 2012. The applicable interest rate for any 28-day auction period
is the term rate established by the auction agent based on the terms of the
auction. The Auction Rate Bond may be converted, in our discretion, to a
daily, seven-day, 35-day, three-month or a semi-annual period or a flexible
auction period. The Auction Rate Bond is subject to optional and mandatory
redemption and to mandatory tender for purchase prior to maturity in the
manner and at the times described herein.
The 2001 Series A Bond, the 2002 Series A Bond and the Auction Rate
Bond are unsecured obligations, ranking equally with our other unsecured and
unsubordinated obligations. In addition, we are limited in our ability to
secure obligations for borrowed money or the deferred purchase price of
property unless we equally and ratably secure our outstanding indebtedness
subject to the Amended and Restated Indenture governing our Bonds.
Principal maturities and sinking fund payments of our outstanding
indebtedness at December 31, 2003 are set forth below:
Year Ending Sinking Fund Principal maturities
December 31 Requirement Total
2004 4,600,000 945,000 $5,545,000
2005 4,900,000 11,031,393 15,931,393
2006 5,200,000 1,125,687 6,325,687
2007 5,500,000 6,228,569 11,728,569
2008 5,900,000 1,340,725 7,240,725
Thereafter 299,600,000 43,462,805 343,062,805
----------- ---------- -----------
$325,700,000 $64,134,179 $389,834,179
============ =========== ============
During 2003 we spent approximately $26.5 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 2004 through 2008:
2004 $32.7 million
2005 $25.3 million
2006 $27.1 million
2007 $30.2 million
2008 $43.2 million
The anticipated large increase in capital expenditures in 2004
represents the construction of a transmission line from the International Power
Plant to University Station via new South Anchorage Bulk Substation and an
overhaul of Beluga unit 7.
We expect that cash flows from operations and external funding sources
will be sufficient to cover operational and capital funding requirements in 2004
and thereafter.
Financing
On August 8, 2003, citing a recent decline in financial margins,
concern regarding regulatory support for the credit quality and certain
challenges associated with Chugach's exceptionally large amount of
non-amortizing debt, Standard & Poor's rating service downgraded Chugach's 2001
Series A, 2002 Series A and 2002 Series B Bonds from "A Stable" rating to
"A-minus Negative" rating.
On December 12, 2003, Fitch Ratings downgraded the above referenced
bonds from "A" to "A-" and "Credit Watch with Negative Outlook" was changed to
"Stable Outlook." The downgrade reflected a negative stance taken by the RCA
toward Chugach in 2003 and tighter projected financial protection measures as a
result.
The ratings with Moody's Investors Service have not been affected. The
2001 Series A and 2002 Series A and B Bonds are still insured by MBIA Insurance
Corporation.
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, 2003.
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 FASB Statement No. 71, Accounting for the Effects of Certain
Types of Regulation. 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 uses U.S. Treasury forward rate lock agreements to hedge
expected interest rates on debt. We accounted for the agreements under SFAS 80
and 71 through December 31, 2000, and SFAS 133, 138 and 71 subsequent to that
date. Gains or losses are treated as regulatory assets or liabilities upon
settlement, which was authorized by the RCA in Order U-01-108(26). Accounting
for derivatives continue to evolve through guidance issued by the Derivatives
Implementation Group (DIG) of the Financial Accounting Standards Board. To the
extent that changes by the DIG modify current guidance, the accounting treatment
for derivatives may change.
Critical estimates also include provision for rate refunds and
allowance for doubtful accounts. Actual results could differ from those
estimates.
New Accounting Standards
In May 2003, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (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.
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, 2003, and 2002:
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%
<FN>
* Includes current portion
</FN>
2002
Fair
Total Debt* 2003 2004 2005 2006 2007 Thereafter Total Value
- ----------- ---- ---- ---- ---- ---- ---------- ----- -----
Fixed rate $866 $945 $11,031 $1,126 $6,228 $314,804 $335,000 $365,279
Average
interest rate 5.60% 5.60% 7.56% 5.60% 5.60% 6.27% 6.29%
Variable rate $10,381 $4,600 $4,900 $5,200 $5,500 $35,500 $66,081 $66,081
Average
interest rate 2.44% 1.40% 1.40% 1.40% 1.40% 1.40% 1.56%
<FN>
* Includes current portion
</FN>
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 $55,450, based on $5,545,000 of variable debt outstanding at
December 31, 2003.
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. (Chugach) as of December 31, 2003 and 2002, 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, 2003. These financial statements are
the responsibility of Chugach's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
the significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Chugach Electric Association,
Inc. as of December 31, 2003 and 2002, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2003 in conformity with accounting principles generally accepted in the United
States of America.
/s/ KPMG, LLP
February 13, 2004
Anchorage, Alaska
Chugach Electric Association, Inc.
Balance Sheets
December 31, 2003 and 2002
Assets 2003 2002
------ ---- ----
Utility plant (notes 1, 3, 12 and 13):
Electric plant in service $744,260,390 $730,439,297
Construction work in progress 16,560,438 20,224,302
---------- ----------
760,820,828 750,663,599
Less accumulated depreciation 293,371,966 279,958,912
----------- -----------
Net utility plant 467,448,862 470,704,687
Other property and investments, at cost:
Nonutility property 3,550 3,550
Investments in associated organizations (note 4) 11,381,796 10,963,715
---------- ----------
11,385,346 10,967,265
Current assets:
Cash and cash equivalents, including repurchase agreements of
$12,663,761 in 2003 and $8,007,424 in 2002 11,185,086 7,284,292
Cash-restricted construction funds 488,846 598,864
Special deposits 222,163 222,163
Accounts receivable, less provision for doubtful accounts of $273,793
in 2003 and $313,545 in 2002 18,812,199 26,410,264
Fuel cost recovery (note 1) 2,032,730 0
Materials and supplies 21,888,794 23,747,590
Prepayments 1,458,649 1,953,350
Other current assets 357,265 336,798
------- -------
Total current assets 56,445,732 60,553,321
Deferred charges, net (notes 5 and 14) 23,511,563 27,989,601
---------- ----------
Total assets $558,791,503 $570,214,874
============ ============
<FN>
See accompanying notes to financial statements.
</FN>
Chugach Electric Association, Inc.
Balance Sheets, Continued
December 31, 2003 and 2002
Liabilities & Equities 2003 2002
---------------------- ---- ----
Equities and margins (note 6 and 7):
Memberships $1,155,818 $1,108,243
Patronage capital 126,341,413 120,148,502
Other 6,718,891 6,221,150
--------- ---------
Total equities and margins 134,216,122 127,477,895
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 51,100,000 55,700,000
National Bank for Cooperatives Promissory Notes payable 63,189,179 64,134,179
---------- ----------
384,289,179 389,834,179
Current liabilities:
Current installments of long-term obligations (notes 8 and 9) 5,545,000 5,165,821
Short-term obligations (note 8) 0 6,081,250
Accounts payable 7,676,906 7,719,974
Provision for rate refund (note 2) 671,071 7,050,000
Consumer deposits 1,834,752 1,826,265
Fuel cost payable (note 1) 0 363,862
Accrued interest 6,165,790 6,381,106
Salaries, wages and benefits 4,886,600 4,977,594
Fuel 9,006,758 7,095,402
Other current liabilities 785,760 2,027,938
------- ---------
Total current liabilities 36,572,637 48,689,212
Deferred credits (note 10) 3,713,565 4,213,588
--------- ---------
Total liabilities and equities $558,791,503 $570,214,874
<FN>
============ ============
See accompanying notes to financial statements.
</FN>
Chugach Electric Association, Inc.
Statements of Revenues, Expenses and Patronage Capital
Years ended December 31, 2003, 2002 and 2001
2003 2002 2001
---- ---- ----
Operating revenues (note 2) $184,032,413 $171,944,918 $178,595,214
Operating expenses:
Fuel 48,667,262 46,822,943 56,130,437
Other power production 13,961,565 13,500,103 12,397,465
Purchased power 18,244,921 18,750,936 14,717,318
Transmission 4,511,002 3,930,902 3,545,707
Distribution 10,866,251 10,869,335 10,417,736
Consumer accounts 5,589,788 5,594,572 5,121,394
Sales expense 0 0 495,523
Administrative, general and other (note 1) 26,370,189 22,251,895 19,574,476
Depreciation 27,792,051 27,649,250 25,096,665
---------- ---------- ----------
Total operating expenses 156,003,029 149,369,936 147,496,721
Interest expense:
On long-term obligations 23,110,239 26,161,891 27,128,662
Charged to construction - credit (411,312) (418,078) (1,063,643)
On short-term obligations 161,901 298,930 1,164,495
------- ------- ---------
Net interest expense 22,860,828 26,042,743 27,229,514
---------- ---------- ----------
Net operating margins 5,168,556 (3,467,761) 3,868,979
Nonoperating margins:
Interest income 325,324 774,814 679,640
Other 679,179 897,761 1,236,907
Property gain (loss) 80,061 (220,964) (246,390)
------ --------- ---------
Assignable margins 6,253,120 (2,016,150) 5,539,136
Patronage capital at beginning of year 120,148,502 125,184,374 122,925,253
Retirement of capital credits and estate payments (note 6) (60,208) (3,019,722) (3,280,015)
-------- ----------- -----------
Patronage capital at end of year $126,341,413 $120,148,502 $125,184,374
============ ============ ============
<FN>
See accompanying notes to financial statements.
</FN>
Chugach Electric Association, Inc.
Statements of Cash Flows
Years ended December 31, 2003, 2002 and 2001
2003 2002 2001
---- ---- ----
Operating activities:
Assignable margins $6,253,120 $(2,016,150) $5,539,136
Adjustments to reconcile assignable margins to net cash
provided by operating activities:
Provision for rate refund (1,400,000) 7,050,000 0
Depreciation and amortization 33,780,103 33,472,159 30,265,821
Capitalization of interest (487,359) (491,349) (1,370,319)
Impairment of long-lived asset 1,846,816 0 0
Property (gains) losses, net (80,061) 220,964 246,390
Write-off of deferred charges 1,088,260 0 0
Other 1,145 1,568 (19,169)
Changes in assets and liabilities:
(Increase) decrease in assets:
Special deposits 0 0 (10,000)
Accounts receivable 7,598,064 (4,107,864) (3,101,488)
Fuel cost recovery (2,032,730) 3,591,963 (676,230)
Materials and supplies 1,858,796 (925,587) (7,464,805)
Prepayments 494,702 (1,325,806) 127,732
Other assets (20,468) (1,044) (3,507)
Deferred charges (1,887,037) (4,479,028) (13,761,107)
Increase (decrease) in liabilities:
Accounts payable (43,068) (3,292,931) 1,519,030
Provision for rate refund (4,978,929)
Consumer deposits 8,487 222,574 279,478
Fuel cost payable (363,862) 363,862 0
Accrued interest (215,316) (996,952) 1,516,668
Other liabilities 578,184 (4,209,158) 4,134,563
Deferred credits (836,016) (14,580,533) (1,584,906)
--------- ------------ -----------
Net cash provided by operating activities 41,162,831 8,496,688 15,637,287
Investing activities:
Extension and replacement of plant (26,526,858) (16,859,047) (36,901,033)
Purchase of investments in associated organizations (419,226) (480,097) (608,864)
--------- --------- ---------
Net cash used in investing activities (26,946,084) (17,339,144) (37,509,897)
Financing activities:
Net transfer of restricted construction funds 110,018 (80,993) (139,023)
Proceeds from long-term obligations 0 180,000,000 150,000,000
Repayments of long-term obligations (5,165,821) (164,638,695) (93,930,350)
Repayments of short-term borrowings (6,081,250) 0 (29,000,000)
Memberships and donations received 545,316 705,061 734,245
Retirement of patronage capital (60,208) (3,019,722) (3,280,015)
Net receipts (refunds) of consumer advances for construction 335,992 (653,670) (392,642)
------- --------- ---------
Net cash provided by (used in) financing activities (10,315,953) 12,311,981 23,992,215
------------ ---------- ----------
Net change in cash and cash equivalents 3,900,794 3,469,525 2,119,605
Cash and cash equivalents at beginning of year $7,284,292 $3,814,767 $1,695,162
---------- ---------- ----------
Cash and cash equivalents at end of year $11,185,086 $7,284,292 $3,814,767
=========== ========== ==========
Supplemental disclosure of cash flow information
Interest expense paid, including amounts capitalized $23,076,144 $27,039,695 $25,712,846
<FN>
=========== =========== ===========
See accompanying notes to financial statements.
</FN>
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2003 and 2002
(1) Description of Business and Significant Accounting Policies
Description of Business
Chugach Electric Association, Inc., (Chugach) is the largest electric
utility in Alaska. Chugach is engaged in the generation, transmission and
distribution of electricity to directly served retail customers in the
Anchorage and upper Kenai Peninsula areas. Through an interconnected
regional electrical system, Chugach's power flows throughout Alaska's
Railbelt, a 400-mile-long area stretching from the coastline of the
southern Kenai Peninsula to the interior of the state, including Alaska's
largest cities, Anchorage and Fairbanks.
Chugach also supplies much of the power requirements of three wholesale
customers, Matanuska Electric Association (MEA), Homer Electric
Association (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).
Management Estimates
In preparing the financial statements, management of Chugach is required
to make estimates and assumptions relating to the reporting of assets and
liabilities and the disclosure of contingent assets and liabilities as of
the date of the balance sheet and revenues and expenses for the reporting
period. Critical estimates include the provision for rate refund and
allowance for doubtful accounts. Actual results could differ from those
estimates.
Regulation
The accounting records of Chugach conform to the Uniform System of
Accounts as prescribed by the Federal Energy Regulatory Commission
(FERC). Chugach meets the criteria, and accordingly, follows the
accounting and reporting requirements of Statement of Financial
Accounting Standards 71, Accounting for the Effects of Certain Types of
Regulation (SFAS 71).
(1) Description of Business and Significant Accounting Policies (continued)
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 Statement of Financial Accounting Standards
No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets
(SFAS 144), In accordance with SFAS No. 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
2002-2003 2001
Steam production plant 2.55% - 2.80% 2.70% - 2.96%
Hydraulic production plant 0.04% - 1.56% 1.33% - 2.88%
Other production plant 2.67% - 7.62% 3.34% - 6.50%
Transmission plant 1.50% - 4.24% 1.85% - 5.37%
Distribution plant 2.13% - 9.22% 2.10% - 4.55%
General plant 2.21% - 20.40% 2.22% - 20.00%
Other 2.35% - 2.75% 1.88% - 2.75%
(1) Description of Business and Significant Accounting Policies (continued)
Chugach uses remaining life rates set forth in the most recently approved
depreciation study. In 2003 an update of the Depreciation Study was
completed utilizing Electric Plant in Service balances as of December 31,
2002. A request to implement the rates developed in that study will be
submitted to the RCA in 2004.
Capitalized Interest
Allowance for funds used during construction (AFUDC) and interest charged
to construction (IDC) - credit are the estimated costs during the period
of construction of equity and borrowed funds used for construction
purposes. Chugach capitalized such funds at the weighted average rate
(adjusted monthly) of 4.8% during 2003, 4.7% during 2002 and 7.5% during
2001.
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.
Fair Value of Financial Instruments
SFAS 107, Disclosures About the Fair Value of Financial Instruments,
requires disclosure of the fair value of certain on and off balance sheet
financial instruments for which it is practicable to estimate that value.
The following methods are used to estimate the fair value of financial
instruments:
Cash and cash equivalents and restricted cash - the carrying amount
approximates fair value because of the short maturity of those
instruments.
Investments in associated organizations - the carrying amount
approximates fair value because of limited marketability and the
nature of the investments.
Consumer deposits - the carrying amount approximates fair value
because of the short refunding term.
Long-term obligations - the fair value is estimated based on the
quoted market price for same or similar issues (note 8).
Treasury rate lock agreements - the fair value is estimated based on
discounted cash flow using current rates.
(1) Description of Business and Significant Accounting Policies (continued)
Financial Instruments and Hedging
Chugach used U.S. Treasury forward rate lock agreements to hedge expected
interest rates on the February 2002 debt re-financings. Chugach accounted
for the agreements under SFAS 80 and 71 through December 31, 2000, and
SFAS 133, 138 and 71 subsequent to that date. Chugach adopted SFAS 133 on
January 1, 2001. Accordingly, the unrealized gain or loss was not
recorded and was treated as a regulatory asset upon settlement (note 6).
This accounting treatment was approved by the RCA in Order U-01-108(26).
See note 2, "Regulatory Matters."
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.
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.
Materials and Supplies
Materials and supplies are stated at the lower of average cost or market.
Deferred Charges and Credits
Deferred charges, representing regulatory assets, are amortized to
operating expense over the period allowed for rate-making purposes. In
accordance with SFAS 71, Chugach's financial statements reflect
regulatory assets and liabilities. Continued accounting under SFAS 71
required certain criteria be met. Management believes Chugach's
operations currently satisfy these criteria. However, if events or
circumstances should change so the criteria are not met, the write off of
regulatory assets and liabilities could have a material effect on the
financial position and results of operations.
(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.
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.
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.
In 1998 a power sales agreement was negotiated between Chugach and
Seward. The contract was approved by the RCA on June 14, 1999 for a
three-year term, which expired on September 11, 2001. The parties
negotiated and executed an Amendment, extending the term of the contract
to January 31, 2006, which was approved by the RCA July 9, 2001. The
RCA's approval required a revision to the contract to include an option
to re-negotiate the terms of the contract if rates are adjusted by the
2000 Test Year general rate case. Seward had three choices within sixty
days of the final order. The choices were to continue the contract using
the rate methodology adopted in the case, negotiate a new contract or
give notice of termination effective twelve months from the effective
date of the final order of the RCA. On December 17, 2003, Seward provided
notice to Chugach of their election to continue with the contract, as
amended, under the new permanent rates established by final order of the
RCA in Docket No. U-01-108.
(1) Description of Business and Significant Accounting Policies (continued)
Fuel Costs
Fuel costs are expensed as fuel is used. 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
under-recovered by $2.0 million in 2003 and over-recovered by $364
thousand in 2002.
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.
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, 2003, 2002 and 2001
Chugach received no unrelated business income.
Reclassifications
Certain reclassifications, which have no affect on assignable margins,
have been made to the 2001 and 2002 financial statements to conform to
the 2003 presentation.
New Accounting Pronouncements
In May 2003, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (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.
(1) Description of Business and Significant Accounting Policies (continued)
That next phase will deal with certain compound financial instruments
including puttable shares, convertible bonds, and dual-indexed financial
instruments.
Chugach plans to implement SFAS 150 effective January 1, 2004. Chugach
does not believe the impact of this statement on its financial statements
will be material.
(2) Regulatory Matters
Chugach filed a general rate case on July 10, 2001, based on the 2000
test year, requesting a permanent base rate increase of 6.5%, and an
interim base rate increase of 4.0%. On September 5, 2001, the RCA granted
a 1.6% interim increase effective September 14, 2001. Chugach filed a
petition for reconsideration and on October 25, 2001, the RCA approved an
interim base rate increase of 3.97%. The additional rate increase was
implemented on November 1, 2001. The interim rate increase was based on a
normalized (adjusted for recurring expenses) test year and a system
ratemaking Times Interest Earned Ratio (TIER) of 1.35. In this filing for
permanent rates, Chugach proposed that margins be calculated using a
return on rate base methodology rather than the TIER methodology
previously used.
As anticipated in Chugach's July 2001 original filing, on April 15, 2002,
Chugach submitted a filing with the RCA to update certain known and
measurable costs and savings that had occurred outside the 2000 Test
Year. In the updated filing, Chugach reduced its base rate increase
request from 6.5% to 5.7%, or approximately $0.9 million in the revenue
requirement on a system basis. The revised filing also reflected an
increase in depreciation expense of approximately $1.5 million due to the
completion of the Beluga Unit 7 re-powering project and a reduction in
annualized interest expense, due to Chugach's recent refinancing efforts,
of $2.4 million. In that revised filing, Chugach continued to request
$11.9 million in margins. As a result of reduced interest costs, this
would have yielded an equivalent system TIER of 1.47.
Three intervenors filed pre-filed testimony with the RCA in July 2002
opposing various aspects of Chugach's proposal. Chugach filed its reply
testimony with the RCA on October 1, 2002. The hearing to resolve the
outstanding issues associated with the 2000 test year rate case took
place in November and December of 2002, concluding on December 13, 2002.
Between February 6, 2003 and January 27, 2004, the RCA issued Order Nos.
26 through 38 addressing various components of Chugach's rate case. The
orders that significantly impact Chugach are discussed below.
(2) Regulatory Matters (continued)
Docket U-01-108, 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 in 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, our motion for stay. Chugach filed the Petition
for Reconsideration with the RCA on February 28, 2003.
Docket U-01-108, 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. The revised
filing reflected adjustments related to the ratemaking treatment of
AFUDC/IDC, interest expense, and legal expense, which had the impact of
increasing Chugach's revenue requirement by $3.1 million and adjusting
the required refund from $7.1 million to $1.9 million.
Docket U-01-108, Order No. 33
On August 26, 2003, the RCA issued Order No. 33 and accepted Chugach's
April 28, 2003 compliance filing, in part. The RCA re-reversed its
earlier decision on the ratemaking treatment of AFUDC/IDC and required
Chugach to comply with the RCA's original ruling contained in Order No.
26 that reduced the recovery of long-term interest expense by $1.2
million associated with AFUDC/IDC.
(2) Regulatory Matters (continued)
Docket U-01-108, Electronic Ruling
On November 7, 2003 the RCA issued an electronic ruling approving
Chugach's September 8 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.
Payment of Refunds
In Order No. 30 the RCA clarified, as requested by Chugach, that the
refund over the interim rate period cannot go below the "floor" of the
rates that were in place prior to Chugach's interim increase. In Order
No. 32 issued on August 15, 2003, the RCA established January 31, 2003 as
the rate effective date of the final rates in this docket such that
Chugach's prior-permanent rates no longer serve as the "floor".
On November 10, 2003 Chugach issued refunds in the following amounts,
pursuant to Superior Court Order dated October 31, 2003, for demand and
energy usage between September 2001 and September 2003:
Homer Electric Association, Inc. $1,762,774
Matanuska Electric Association, Inc. $2,901,290
Seward Electric System $ 103,307
Chugach issued additional refund amounts totaling $70,894 to HEA and
$162,015 to MEA on December 29, 2003 for refund adjustments related to
Chugach's pre-refinancing activity that took place in February 2002.
Additional payments will be made to reflect interest on the refund
amounts. The RCA has not yet determined what interest rate will be
applied.
Customers in Chugach's Small General Service rate class may also receive
a refund. Chugach expects that approximately 2,100 Small General Service
customers will receive refunds for electric service provided between
January 31, 2003 and November 10, 2003. In Order No. 38, the RCA ruled
that interest on Small General Service refunds would be applied at an
annual rate 3.034 percent. Chugach expects the refund amount to the Small
General Service class will total approximately $0.6 million, including
interest. Chugach expects this refund to be completed by April 2004 and
is recorded as a provision for rate refund at December 31, 2003.
(2) Regulatory Matters (continued)
Docket U-01-108, Order No. 30 Appeal
Chugach has appealed the RCA's decisions in Order No. 26 to modify
Chugach's generation and transmission TIER of 1.10, from the previously
authorized level of 1.15 and a distribution TIER of approximately 1.6.
Chugach asserts that such a disparity in TIER violates the requirements
of AS 42.05.141(a)(3) and AS 42.05.391 (a) in that the resulting rates
are not just, fair and reasonable and yield an unreasonable difference as
to rates between Chugach's retail and wholesale customers. Chugach
further asserts that the resulting rates grant an unreasonable preference
or advantage to Chugach's wholesale customers by creating an unreasonable
prejudice or disadvantage to its retail customers.
On April 29, 2003, Chugach filed an appeal in Alaska Superior Court on
two issues. In Order No. 30 of this docket, the RCA reconsidered and
reversed its earlier decision and agreed with Chugach that requiring
AFUDC/IDC as an offset to long-term interest expense would cause
under-recovery and should, therefore, not be required. However, the
specific language of the RCA's order on reconsideration limited its
ruling to projects commenced and concluded within the test year. This
could cause under-recovery of project costs over the life of the asset
resulting in a confiscatory rate. Chugach has filed an appeal as to this
portion of the RCA's decision on reconsideration in Order No. 30.
On May 13, 2003, MEA filed a cross appeal challenging several of the
RCA's decisions.
On July 21, 2003, the Superior Court of Alaska granted Chugach's motion
for stay on condition that the excess interim rate refund be placed into
an interest bearing escrow account and the revenues received from future
rates, which may be subject to refund, be held in the same account.
On October 3, 2003 Chugach filed for a motion to dissolve the stay that
was granted by the Superior Court on July 21. Based on the results of RCA
orders, subsequent to Chugach's request for stay in Superior Court,
Chugach determined that removal of the stay on implementation of rates
pursuant to Order 33 would increase Chugach revenues by approximately
$0.7 million on an annual basis. Chugach will continue to pursue all
issues raised in its appeals in Alaska Superior Court.
On October 31, 2003, the superior court issued an order granting
Chugach's motion to remove stay, releasing the escrow funds and ordering
Chugach to pay refunds within 10 days of the order based upon the RCA's
orders.
(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, leaving
approximately $700 thousand at December 31, 2003, which represented the
provision for rate refund due Chugach's small commercial customers and
interest associated with wholesale refunds.
(3) Utility Plant
Major classes of electric plant as of December 31 are as follows:
2003 2002
---- ----
Electric plant in service:
Steam production plant $60,392,869 $60,392,869
Hydraulic production plant 17,990,505 17,904,105
Other production plant 109,737,781 103,046,773
Transmission plant 215,716,581 208,103,602
Distribution plant 202,573,670 188,775,770
General plant 52,053,256 52,273,770
Unclassified electric plant in service* 77,256,535 91,346,892
Equipment under capital lease 0 56,323
Other 8,539,193 8,539,193
--------- ---------
Total electric plant in service 744,260,390 730,439,297
Construction work in progress 16,560,438 20,224,302
---------- ----------
Total electric plant in service and
construction work in progress $760,820,828 $750,663,599
============ ============
<FN>
*Unclassified electric plant in service consists of complete
unclassified of general plant, generation, transmission and
distribution projects
</FN>
Depreciation of unclassified electric plant in service has been included
in functional plant depreciation accounts in accordance with the
anticipated eventual classification of the plant investment.
(4) Investments in Associated Organizations
Investments in associated organizations, which are non-marketable and
accounted for at cost, include the following at December 31:
2003 2002
---- ----
National Rural Utilities Cooperative Finance
Corporation (NRUCFC) $6,095,980 $6,095,980
National Bank for Cooperatives (CoBank) 5,125,524 4,703,331
NRUCFC capital term certificates 43,647 44,631
Other 116,645 119,773
------- -------
$11,381,796 $10,963,715
=========== ===========
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:
2003 2002
---- ----
Debt issuance and reacquisition costs $12,569,713 $14,155,863
Refurbishment of transmission equipment
225,309 234,568
Computer software and conversion 3,334,230 5,666,620
Studies (note 14) 2,942,082 1,952,074
Business venture studies 172,216 601,217
Fuel supply negotiations 278,745 329,901
Major overhaul of steam generating unit 2,287,466 2,701,076
Environmental matters and other 88,071 154,205
Other regulatory deferred charges 1,613,731 2,194,077
--------- ---------
$23,511,563 $27,989,601
=========== ===========
At December 31, 2003 and 2002, $3.6 million and $3.4 million,
respectively, of total deferred charges represent regulatory assets in
progress and not currently being amortized.
(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,
2003, Chugach had assigned $122,104,444 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 2001, the Board of Directors authorized the retirement of
$3,000,000 of retail patronage for 1985.
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)
Estate payments in the amount of $60,208, $250,154 and $280,015 were made
in 2003, 2002 and 2001, respectively.
Following is a five-year summary of anticipated capital credit
retirements:
Year ending Total
December 31,
2004 $ 3,000,000
2005 $ 3,000,000
2006 $ 2,600,000
2007 $ 2,900,000
2008 $ 3,500,000
(7) Other Equities
A summary of other equities at December 31 follows:
2003 2002
---- ----
Nonoperating margins, prior to 1967 $23,625 $23,625
Donated capital 183,633 183,807
Unclaimed capital credit retirement 6,511,633 6,013,718
--------- ---------
$6,718,891 $6,221,150
(8) Debt
Long-term obligations at December 31 are as follows: 2003 2002
---- ----
CoBank 7.76% note maturing in 2005, with interest payable monthly 10,000,000 10,000,000
CoBank 2.75% note, with principal due in 2007 and 2012, and with interest
payable monthly 10,000,000 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 B Bond of a rate set for 28-day auction periods, maturing in
2012, with interest payable monthly and principal due annually 55,700,000 60,000,000
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
CoBank 2.75% note maturing in 2022, with interest payable monthly and
principal due annually beginning in 2003 44,134,179 45,000,000
---------- ----------
Total long-term obligations 389,834,179 395,000,000
Less current installments 5,545,000 5,165,821
--------- ---------
Long-term obligations, excluding current installments $384,289,179 $389,834,179
============ ============
(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 in
note 2, "Regulatory Matters," 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.
At December 31, 2003, Chugach was in compliance with all covenants
described above.
(8) Debt (continued)
Maturities of Long-term Obligations
Long-term obligations at December 31, 2002, mature as follows:
Year ending
December 31 Sinking Fund Sinking Fund Sinking Fund Principal maturities Total
-------------------- -----
Requirements Requirements Requirements
2001 Series A 2002 Series A 2002 Series B CoBank
Bonds Bonds Bonds Mortgage bonds
2004 0 0 4,600,000 945,000 5,545,000
2005 0 0 4,900,000 11,031,393 15,931,393
2006 0 0 5,200,000 1,125,687 6,325,687
2007 0 0 5,500,000 6,228,569 11,728,569
2008 0 0 5,900,000 1,340,725 7,240,725
Thereafter 150,000,000 120,000,000 29,600,000 43,462,805 343,062,805
----------- ----------- ---------- ---------- -----------
$150,000,000 $120,000,000 $55,700,000 $64,134,179 $389,834,179
============= ============= ============ =========== ============
Short-term obligations
Chugach had an annual line of credit of $35,000,000 available in 2002
with CoBank. On December 27, 2002, Chugach chose to reduce the available
line of credit to $20,000,000. The CoBank line of credit expires December
31, 2004. At December 31, 2003, there was no outstanding balance on this
line of credit. At December 31, 2002, there was $6,081,250 million
outstanding on this line of credit, which carried an interest rate of
3.17%. In addition, Chugach had an annual line of credit of $50,000,000
available at December 31, 2003 and 2002 with NRUCFC. At December 31, 2003
and 2002, 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.
In May 2001, Chugach reacquired $10,000,000 of its 1991 Series A 2022
Bond at a premium of 111.00. Total transaction costs, including accrued
interest and premium, were $11,242,178.
In December 2001, Chugach reacquired $5,000,000 of its 1991 Series A 2022
Bond at a premium of 111.00. Total transaction costs, including accrued
interest and premium, were $5,661,711.
The premiums paid are reflected as a regulatory asset and amortized over
the life of the corresponding debt.
(8) Debt (continued)
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:
2003 2002
---- ----
Carrying Fair Carrying Fair
Value Value Value Value
Long-term obligations
(including current installments) $389,834 $418,424 $395,000 $425,279
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:
2003 2002
---- ----
Refundable consumer advances for construction $2,528,271 $2,817,614
Estimated initial installation costs for transformers and
meters 369,153 364,766
Post retirement benefit obligation 405,700 405,700
New business venture 0 30,256
Other 410,441 595,252
------- -------
$3,713,565 $4,213,588
========== ==========
(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 $2,529,000 in 2003, $2,253,000 in 2002 and $1,990,000 in
2001. In 2003, 2002 and 2001, Chugach contributed $1,492,000, $1,401,000
and $1,397,000, 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
$44,000,000. Under a worst-case scenario, Chugach could be faced with
annual expenditures of approximately $4.1 million as a result of
Chugach's Bradley Lake take-or-pay obligations. Management believes that
such expenditures, if any, would be recoverable through the fuel
surcharge ratemaking process. Upon the default of a Bradley Lake
participant, and subject to certain other conditions, AEA, through Alaska
Industrial Development and Export Authority, is entitled to increase each
participant's share of costs pro rata, to the extent necessary to
compensate for the failure of another participant to pay its share,
provided that no participant's percentage share is increased by more than
25%.
The following represents information with respect to Bradley Lake at June
30, 2003 (the most recent date for which information is available).
Chugach's share of expenses was $4,212,072 in 2003, $4,343,562 in 2002
and $3,929,614 in 2001 and is included in purchased power in the
accompanying financial statements.
(In thousands) Total Proportionate Share
----- -------------------
Plant in service $ 308,259 $ 93,711
Accumulated depreciation (81,475) (24,768)
Interest expense 9,004 2,737
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 by double
majority 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.
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.
Chugach is the principal supplier of power under long-term wholesale
power contracts with MEA and HEA. These contracts represented $55.8
million or 30.8% of operating revenues in 2003, $57.0 million or 33.7% in
2002 and $57.9 million or 32.9% in 2001. These
(14) Commitments, Contingencies and Concentrations (continued)
contracts will expire in 2014.
Fuel is purchased directly from Marathon Oil Company, ChevronTexaco, ML&P
and ConocoPhillips. The cost of fuel purchased from Marathon Oil Company
represented 47.4% in 2003, 45.6% in 2002 and 45.0% in 2001 of total fuel
costs.
Cooper Lake Hydroelectric Plant
Chugach discovered polychlorinated biphenyls (PCBs) in paint, caulk and
grease at the Cooper Lake Hydroelectric plant during initial phases of a
turbine overhaul. A FERC approved plan, prepared in consultation with the
Environmental Protection Agency (EPA), was implemented to remediate the
PCBs in the plant. As a condition of its approval of the license
amendment for the overhaul project, FERC required Chugach to also
investigate the presence of PCBs in Kenai Lake. A sampling plan was
developed by Chugach in consultation with state and federal agencies and
approved by FERC. In 2000, Chugach sampled sediments and fish collected
from Kenai Lake and other waters. While low levels of PCBs were found in
some sediment samples taken near the plant, no pathway from sediment to
fish was established. While the levels of PCBs in fish from Kenai Lake
were similar to levels found in fish from other lakes within the region,
Chugach conducted additional sampling and analysis of fish in Kenai Lake
and other waters and filed Chugach's final report dated April 1, 2002
with FERC, which analyzed the results of the sampling. Based on these
analyses, Chugach concluded that no further PCB sampling and analysis in
Kenai Lake was necessary. In a letter dated June 13, 2002, FERC informed
Chugach that its review of the report supported Chugach's conclusions and
agreed Chugach was not required to conduct further PCB sampling and
analysis in Kenai Lake. In its recent order in Chugach's general rate
case, Order U-01-108(26), the RCA permitted the costs associated with the
overhaul and the PCB remediation to be recovered through rates.
Consequently, management believes the costs of the PCB remediation and
studies will have no material impact on Chugach's financial condition or
results of operations.
Legal Proceedings
Matanuska Electric Association, Inc., v. Chugach Electric Association,
Inc., Superior Court Case No. 3AN-99-8152 Civil
This action is a claim for a breach of the Tripartite Agreement, which is
the contract governing the parties' relationship for a 25-year period
from 1989 through 2014 and governing Chugach's sale of power to MEA
during that time. MEA asserted Chugach breached that contract by failing
to provide information, by failing to properly manage Chugach's long-term
debt, and by failing to bring Chugach's base rate action to a Joint
Committee before presenting it to the RCA. The committee is defined in
the power sales contract and consists of one MEA and two Chugach board
members. All of MEA's
(14) Commitments, Contingencies and Concentrations (continued)
claims have been dismissed. On April 29, 2002, MEA appealed the Superior
Court's decisions relating to Chugach's financial management and
Chugach's failure to bring Chugach's base rate action to the joint
committee before filing with the RCA to the Alaska Supreme Court. We
cross-appealed the Superior Court's decision not to dismiss the financial
management claim on jurisdictional and res judicata grounds. Oral
argument was heard by the Supreme Court on April 15, 2003. Management is
uncertain as to the outcome and expects a decision within twelve months.
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
$.000626 per kWh to the current rate of $.000392, effective October 1,
2003.
(15) Quarterly Results of Operations (unaudited)
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 44,176,751 38,351,606 38,320,588 35,154,084
Net Interest 5,471,421 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
========== ============ ============ ==========
2002 Quarter Ended
Dec. 31* Sept. 30 June 30 March 31
-------- -------- ------- --------
Operating Revenue $39,015,326 $41,523,323 $42,837,727 $48,568,542
Operating Expense 39,742,069 35,548,872 36,589,007 37,489,988
Net Interest 6,013,016 5,994,890 6,039,051 7,995,786
--------- --------- --------- ---------
Net Operating Margins (6,739,759) (20,439) 209,669 3,082,768
Non-Operating Margins 735,253 94,646 122,622 499,090
------- ------ ------- -------
Assignable Margins (6,004,506) $74,207 $332,291 $3,581,858
=========== ======= ======== ==========
*The reduction to operating revenue described in note 2 "Regulatory
Matters" was recorded in the 2002 quarter ended December 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 principal executive (CEO) and principal 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 Securities and Exchange Commission. 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. We have found no facts that would require us to take any corrective
actions with regard to significant deficiencies or material weaknesses.
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............................ 62 Chief Executive Officer
Lee D. Thibert.............................. 48 Sr. Vice President, Power Delivery
Michael R. Cunningham....................... 54 Chief Financial Officer
William R. Stewart.......................... 57 Sr. Vice President, Administration
Bradley W. Evans............................ 49 Sr. Vice President, Energy Supply
Bruce Davison............................... 55 Chairman and Director
H. A. (Red) Boucher......................... 83 Vice Chairman and Director
Patricia B. (Pat) Jasper.................... 74 Secretary and Director
Jeffrey W. Lipscomb......................... 53 Treasurer and Director
Samuel W. Cason............................. 44 Director
Christopher Birch........................... 53 Director
David Cottrell.............................. 56 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 Sr. Vice President, Power Delivery on June
3, 2002. Prior to that appointment he had served as Executive Manager,
Transmission & Distribution Network Services since the June 1, 1997
reorganization. Prior to that he was Executive Manager, Operating Divisions from
June of 1994. Before moving up to the Executive Manager position, he served as
Director of Operations from May 1987.
William R. Stewart was appointed Sr. Vice President, Administration on
June 5, 2002. Prior to that appointment he had served as Executive Manager,
Retail Services since the June 1, 1997 reorganization. Prior to that, he was
Executive Manager, Administration from July 1987 to June 1, 1997. He was our
Division Director of Administration from January 1984 to July 1987 and Staff
Assistant to the General Manager of Chugach from November 1982 to January 1984.
He has been employed at Chugach since 1969.
Michael R. Cunningham was appointed Chief Financial Officer on June 5,
2002. Prior to that appointment he had served as Controller since 1986. Prior to
that he was Budget Analyst and Manager of Accounting since beginning his Chugach
employment in 1982. Prior to his Chugach employment, Mr. Cunningham spent 15
years in various capacities with Pacific Northwest Bell Telephone Company.
Bradley W. Evans was appointed Sr. Vice President, Energy Supply on
June 5, 2002. Prior to that appointment he had served as Director of Energy
Supply since February 26, 2001. Prior to his Chugach employment, Mr. Evans
served as Manager, System Dispatch for Golden Valley Electric Association.
Board of Directors
Bruce Davison serves as Chairman of the Board and also chairs the
board's Operations Committee. He had served as the Secretary of the Board since
April 1998. Mr. Davison was first appointed to the Board of Directors in June
1997. Prior to his appointment, he served two years on our Bylaws Committee. He
is an attorney and professional engineer and a partner in the law firm of
Davison & Davison, Inc.
Red Boucher serves as Vice Chairman of the Board and chairs the board's
Technology Committee and the Government and External Affairs Committee. He has
served on the board since 1999 and has previously served as 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 and Audit committees. 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. 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. Mr. Birch is a professional civil engineer, licensed in Alaska
since 1978 and Director of Engineering, Environment and Planning at the Ted
Stevens Anchorage International Airport.
Sam Cason is a self-employed attorney. He was elected to a 3-year term
on the board in 2002.
Code of Ethics
Chugach is in the process of creating a code of ethics that would apply
to its principal executive officer, principal financial officer, principal
accounting officer and any person performing similar functions. The code of
ethics is expected to be finalized by March 31, 2004. It will also be 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 2003, and for all such
executive officers as a group:
Name Principal Position Year Salary Bonus Total
Evan J. Griffith Chief Executive Officer 2003 $201,685 $0 $201,685
2002 172,239 0 172,239
2001 142,884 7,770 150,654
Lee D. Thibert Sr. Vice President, 2003 $149,103 $5,939 $155,042
Power Delivery 2002 154,881 0 154,881
2001 142,425 0 142,425
Michael R. Cunningham Chief Financial Officer 2003 $132,316 $0 $132,316
2002 130,220 0 130,220
2001 119,093 0 119,093
William R. Stewart Sr. Vice President, 2003 $161,879 $3,712 $165,591
Administration 2002 159,839 0 159,839
2001 158,902 0 158,902
Bradley W. Evans Sr. Vice President, 2003 $135,398 $5,197 $140,595
Energy Supply 2002 128,227 0 128,227
2001 96,472 0 96,472
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 80
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 completes 1,000 hours of service either in his first twelve
consecutive months of employment or in any calendar year for us or certain other
employers in rural electrification (related employers). Pension benefits vest at
the rate of 10% for each of the first four years of vesting service and become
fully vested and nonforfeitable on the earlier of the date a participant has
five years of vesting service or the date the participant attains age fifty-five
while employed by us or a related employer. A participant is credited with one
year of vesting service for each calendar year in which he performs at least one
hour of service for us or a related employer. Pension benefits are generally
paid upon the participant's retirement or death. A participant may also elect to
receive pension benefits while still employed by us if he has reached his normal
retirement date by completing thirty years of benefit service (defined below)
or, if earlier, by attaining age sixty-two. A participant may elect to receive
actuarially reduced early retirement pension benefits before his normal
retirement date provided he has attained age fifty-five.
Pension benefits paid in normal form are paid monthly for the remaining
lifetime of the participant. Unless an actuarially equivalent optional form of
benefit payment to the participant is elected, upon the death of a participant
the participant's surviving spouse will receive pension benefits for life equal
to 50% of the participant's benefit. The annual amount of a participant's
pension benefit and the resulting monthly payments the participant receives
under the normal form of payment are based on the number of his years of
participation in the Plan (benefit service) and the highest five-year average of
the annual rate of his base salary during the last ten years of his
participation in the Plan (final average salary). Annual compensation in excess
of $200,000, as adjusted by the Internal Revenue Service for cost of living
increases, is disregarded after January 1, 1989. The participant's annual
pension benefit at his normal retirement date is equal to the product of his
years of benefit service 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, 2003 taken into account under the
Plan for the executive officers is shown below. Base salary for 2003 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 13 years, 4 months $188,718
Lee D. Thibert Sr. Vice President, Power
Delivery 15 years, 7 months 148,012
Michael R. Cunningham Chief Financial Officer 20 years, 1 month 130,000
William R. Stewart* Sr. Vice President,
Administration 1 year, 2 months 142,147
Bradley W. Evans Sr. Vice President, Energy Supply
2 years, 10 months 135,012
* 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
$188,718. 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, 2003.
Fees and Services
KPMG LLP has provided certain audit, audit-related, tax and non-audit
services, the fees for which are as follows:
2003 2002
Audit services and quarterly reviews $65,400 $46,800
Audit-related services (registration statement) $0 $38,785
Non-audit services:
Single audit and employee benefit plans $15,850 $14,750
Tax consulting and return preparation $2,500 $795
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, 2003 and 2002 were approved by the Audit
Committee.
PART IV
Item 15 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
Page
Financial Statements
Included in Part IV of this Report:
Independent Auditors' Report 40
Balance Sheets, December 31, 2003 and 2002 41-42
Statements of Revenues, Expenses and Patronage Capital,
Years ended December 31, 2003, 2002 and 2001 43
Statements of Cash Flows,
Years ended December 31, 2003, 2002 and 2001 44
Notes to Financial Statements 45-69
Financial Statement Schedules
Included in Part IV of this Report:
Independent Auditors' Report 79
Schedule II - Valuation and Qualifying Accounts,
Years ended December 31, 2003, 2002 and 2001 80
Other schedules are omitted as they are not required or are not applicable, or
the required information is shown in the applicable financial statements or
notes thereto.
Independent Auditors' Report
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association,
Inc. as of December 31, 2003 and 2002, 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, 2003. In connection with our audits of the
financial statements, we have also audited the financial statement schedule
listed in Item 15 herein. These financial statements and financial statement
schedule are the responsibility of the Association's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standard generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Chugach Electric Association,
Inc. as of December 31, 2003 and 2002, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2003, in conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly, in all material respects, the information set forth
therein.
/s/ KPMG, LLP
Anchorage, Alaska
February 13, 2004
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, 2003 (313,545) (326,842) 366,594 (273,793)
December 31, 2002 (318,757) (344,472) 349,684 (313,545)
December 31, 2001 (441,933) (116,881) 240,057 (318,757)
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.
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.
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.
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.
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.
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)
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.
REPORTS ON FORM 8-K
Reference is made to the January 22, 2003, 8K, which discussed a Master
Loan Agreement that Chugach and CoBank entered into dated December 27, 2002.
Reference is made to the January 31, 2003, 8K, which discussed Order No.
26 that Chugach received from the RCA on February 6, 2003, concerning Chugach's
2000 Test Year rate case.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized on March 29, 2004.
CHUGACH ELECTRIC ASSOCIATION, INC.
By: /s/ Evan J. Griffith
Evan J. Griffith, Chief Executive Officer
Date: March 29, 2004
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below on March 29, 2004, 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 Senior Vice President, Power Delivery
/s/ Michael R. Cunningham
Michael R. Cunningham Chief Financial Officer
(Principal Financial Officer)
/s/ William R. Stewart
William R. Stewart Senior Vice President, Administration
/s/ Bradley W. Evans
Bradley W. Evans Senior Vice President, Energy Supply
/s/ Bruce Davison
Bruce Davison Director & Chairman of the Board
/s/ H.A. Boucher
H. A. Boucher 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 2003 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.