UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(AMENDMENT NO. 1)
(x) Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2000
( ) Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from_____________________to___________________________
Commission file Number 33-42125
Chugach Electric Association, Inc.
(Exact name of registrant as specified in its charter)
Alaska 92-0014224
(State or other jurisdiction
of incorporation or organization) (I.R.S. Employer Identification No.)
5601 Minnesota Drive, Anchorage, Alaska 99518
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (907) 563-7494
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
---------------------------- ---------------------------------------------
---------------------------- ---------------------------------------------
Securities registered pursuant to Section 12(g) of the Act:
- --------------------------------------------------------------------------------
(Title of class)
- --------------------------------------------------------------------------------
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securites Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. /x/ Yes / / No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. N/A
State the aggregate market value of the voting stock held by non-affiliates of
the registrant. The aggregate market value shall be computed by reference to
the price at which the stock was sold, or the average bid and asked prices of
such stock, as of a specified date within 60 days prior to the date of filing.
(See definition of affiliate in Rule 405, 17 CFR 230.405). N/A
CHUGACH ELECTRIC ASSOCIATION, INC.
2000 Form 10-K/A
(Amendment No. 1)
Annual Report
Table of Contents
PART I Page
Item 1 - Business 1
PART II
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations 9
Item 7A - Quantitative and Qualitative Disclosures About Market Risk 18
SIGNATURES 20
INTRODUCTORY STATEMENT
Chugach Electric Association, Inc. hereby amends Items 1, 7 and 7A of
its Form 10-K for the fiscal year ended December 31, 2000, as filed with the
Securities and Exchange Commission on March 30, 2001, to correct MWh energy
sales to customers stated in Item 1 and Item 7. Chugach has also included an
update to current interest rates stated in Item 7, the value of the
Treasury-rate lock agreement stated in Item 7 and the current amount of
short-term debt outstanding as stated in Item 7A.
PART I
Item 1 - Business
General
Chugach Electric Association, Inc., is the largest electric utility in
Alaska. We are engaged in the generation, transmission and distribution of
electricity to approximately 71,800 metered locations in the Anchorage and upper
Kenai Peninsula areas. Through an interconnected regional electrical system, our
energy is distributed throughout Alaska's Railbelt, a 400-mile-long area
stretching from the coastline of the southern Kenai Peninsula to the interior of
the state, including Alaska's largest cities, Anchorage and Fairbanks. Neither
we nor any other electric utility in Alaska has any connection to the electric
grid of the mainland United States or Canada.
Through direct service to retail customers and indirectly through
wholesale and economy energy sales, we provide some or all of the electricity
used by approximately two-thirds of Alaska's electric customers. We also supply
much of the power requirements of three wholesale customers, Matanuska Electric
Association ("MEA"), Homer Electric Association ("HEA") and the City of Seward
("Seward"). In addition, on a periodic basis, we provide electricity to
Anchorage Municipal Light & Power ("AML&P"). AML&P has about 30,000 meters.
We have approximately 511 megawatts of installed generating capacity
provided by 17 generating units at our five owned power plants: Beluga Power
Plant, Bernice Lake Power Plant, International Generating Station, Cooper Lake
Hydroelectric Plant and Eklutna Hydroelectric Project, in which we own a 30%
interest. Approximately 96% (by rated capacity) of our generating capacity is
fueled by natural gas, which we purchase under long-term gas contracts. The
remainder of our generating resources are hydroelectric facilities. In 2000,
approximately 85% of our energy was generated at our Beluga facility. We
purchase up to 27.4 megawatts from the Bradley Lake Hydroelectric Project and up
to 40 megawatts from the Nikiski power plant on the Kenai Peninsula. We operate
1,602 miles of distribution line and 402 miles of transmission line. For the
year ended December 31, 2000, we sold 2.4 billion kilowatt hours ("kWh") of
power.
We were organized as an Alaska electric cooperative in 1948.
Cooperatives are business organizations that are owned by their members. As
not-for-profit organizations, cooperatives are intended to provide services to
their members at cost, in part by eliminating the need to produce profits or a
return on equity. Today, cooperatives operate throughout the United States in
such diverse areas as utilities, agriculture, irrigation, insurance and credit.
All cooperatives are based upon similar principles and legal foundations.
Because members' equity is not considered an investment, a cooperative's
objectives and policies are oriented to serving member interests, rather than
maximizing return on investment.
Our members are the consumers of the electricity sold by us. As of
December 31, 2000, we had approximately 57,900 retail members receiving service
at approximately 71,800 metered locations and three major wholesale customers.
No individual retail customer receives more than 5% of our power. Our business
and affairs are managed by the General Manager and are overseen by a
seven-member Board of Directors. Directors are elected at large by the
membership and serve three-year staggered terms. Each member is entitled to one
vote. In addition to voting for directors, members have voting rights with
respect to mergers and the sale, lease, or other disposition (except by mortgage
or deed of trust) of all or a substantial portion of our property.
Our customers are billed per a tariff rate on a monthly basis for
electrical power consumed during the preceding month. Billing rates are approved
by the Regulatory Commission of Alaska ("RCA") (see "Rate Regulation and Rates"
below).
Rates (derived from the historic cost of service basis) may generate
revenues in excess of current period costs (net operating margins and
nonoperating margins) in any year and such excess is designated on our
Statements of Revenues, Expenses and Patronage Capital as "assignable margins."
Retained assignable margins are designated on our balance sheet as "patronage
capital" that is assigned to each member on the basis of patronage.
We are a rural electric cooperative that is exempt from federal income
taxation as an organization described in Section 501(c)(12) of the Internal
Revenue Code ("Code"). Alaska electric cooperatives must pay to the State of
Alaska, in lieu of state and local ad valorem, income and excise taxes, a tax at
the rate of $0.0005 per kWh of electricity sold in the retail market during the
preceding year. In addition, we collect a regulatory cost charge of $.000318 per
kWh of retail electricity sold. This charge is assessed to fund the operations
of the RCA. It is a pass-through and thus does not impact our margins.
Our workforce consists of approximately 355 full -time employees.
Approximately two-thirds of our employees are members of the International
Brotherhood of Electrical Workers ("IBEW"). We have three collective bargaining
agreements with the IBEW that are in effect through June 30, 2003. We also have
an agreement with Hotel Employees, Restaurant Employees, Local 878 in effect
through June 30, 2003. We believe our relationship with our employees is good.
Our Service Areas
Our service areas and those of our wholesale and economy energy
customers are often described collectively as the Railbelt region of Alaska
because the three geographic areas (the Southcentral, the Kenai Peninsula and
the Interior) are linked by the Alaska Railroad.
Anchorage is the trade, service and financial center for most of Alaska
and serves as a major center for many state governmental functions. Other
significant contributing factors to the Anchorage economy include a large
federal government and military presence, tourism, air and rail transportation
facilities and headquarters support for the petroleum, mining and other basic
industries located elsewhere in the state.
The Matanuska-Susitna Borough is immediately north of the Municipality
of Anchorage, centered around the communities of Palmer and Wasilla. Although
agriculture, tourism, mining and forestry are factors in the economy of the
Matanuska-Susitna Borough, the economic well-being of the area is closely tied
to that of Anchorage and many Matanuska-Susitna residents commute to jobs in
Anchorage.
The Kenai Peninsula is south of Anchorage with an economy substantially
independent of the Anchorage area. The most significant basic industry on the
Kenai Peninsula is the production and processing of petroleum products from the
Cook Inlet region. Other important basic industries include tourism and fish
harvesting and processing. Principal communities on the Kenai Peninsula are
Homer, Seward, Kenai and Soldotna.
Fairbanks is the center of economic activity for the central part of
the state (known as the Interior). Fairbanks (250 air miles north of Anchorage
and about 400 air miles south of Alaska's northern border) is Alaska's second
largest city. Basic economic activities in the Fairbanks region include federal
and state government and military operations, the University of Alaska, tourism
and support of natural resource development in the Interior and northern parts
of the state. Recently a major gold mine commenced operation near Fairbanks. The
Trans-Alaska Pipeline System (which transports crude oil) passes near Fairbanks
on its route from the North Slope oilfield to Valdez.
Competition
Nationwide, the electric utility industry is entering a period of
unprecedented upheaval and restructuring. We have taken several steps to be more
effectively positioned to meet the challenge of a competitive market for
electricity.
We have been active at the Alaska Legislature in support of the
customer's right to choose their electric power supplier. For example, we have
requested access over a neighboring utility's distribution and transmission
system and asked the RCA to enforce the request. The RCA ruled that retail
competition is permitted in Alaska only after prior review and approval by the
RCA. We are appealing this ruling in the courts. Virtually all other Alaskan
utilities have opposed our efforts to develop competition and are treating their
service territories as exclusive. At this time no bill relating to customer
choice has moved out of legislative committee. It is not possible to predict the
outcome of this legislative process.
We have made organizational changes in preparation for competition.
Recognizing that the new marketplace will probably be "unbundled" along the
functional lines of generation, transmission and distribution and retail
services, our organizational structure reflects these functions. Operating with
three divisions: Finance and Energy Supply, Transmission and Distribution
Network Services and Retail Services, we have positioned ourselves to meet
competition in the electric industry. We continue to operate a key account
program for larger customers and are developing new services to enhance existing
customers' satisfaction.
It is our objective to continually improve the efficiency and cost
effectiveness of our operations. We participate in customer satisfaction
surveys, benchmark the performance of system operations against an international
peer group and perform studies on how to implement business process best
practices. These ongoing programs focus on distribution and transmission lines,
substations, power plants, fleet operations and administrative services.
Rate Regulation and Rates
We are subject to rate regulation by the RCA. We can seek increases in
our demand and energy charges by filing general rate cases with the RCA. While
the formal ratemaking process typically takes nine months to one year, it is
within the RCA's authority to authorize, after a notice period, rate changes on
an interim, refundable basis. In addition, the RCA has been willing to open
limited reviews of matters to resolve specific issues from which expeditious
decisions can often be rendered.
The RCA has exclusive regulatory control of our rates, subject to
appeal to the Alaska Superior Court and the Alaska Supreme Court under the
Alaska Administrative Procedures Act. Under Alaska law, financial covenants of
an Alaskan electric cooperative contained in a debt instrument will be valid and
enforceable, and rates set by the RCA must be adequate to meet those covenants.
We will continue to recover changes in our fuel and purchased power
expenses through routine fuel surcharge filings with the RCA. See "Management's
Discussion and Analysis - Results of Operations - Rate Regulation and Rates."
The 1991 Indenture governing all of our outstanding bonds requires us
to set rates designed to yield margins for interest equal to at least 1.20 times
total interest expense. The authorized rate-setting Times Interest Earned Ratio
("TIER") level of 1.35 has allowed us to achieve margins for interest greater
than 1.20. For the year ended December 31, 2000, our achieved TIER was 1.39.
Sales to Customers
The following table shows the energy sales to and electric revenues
from our retail, wholesale, and economy energy customers for the year ended
December 31, 2000:
Percent of Total
MWh 2000 Revenues 2000 Revenues
Direct retail sales:
Residential........ 509,799 $ 51,288,657 33%
Commercial......... 586,352 47,248,033 31%
Total.............. 1,096,151 $ 98,536,690 64%
Wholesale sales:
MEA................ 549,517 $ 27,252,051 17%
Homer.............. 436,112 19,060,244 12%
Seward............. 59,453 2,369,550 2%
Total.............. 1,045,082 $ 48,681,845 31%
Economy energy sales(1).. 267,855 $ 7,820,998 5%
Total sales to customers. 2,409,088 $155,039,533 100%
Miscellaneous energy revenue ------ $ 2,331,133
Total energy revenues $157,370,666
(1) All economy sales were made to GVEA.
Retail Customers
Service Territory
Our retail service area covers the populated areas of Anchorage (other
than downtown Anchorage) as well as remote mountain areas and villages. The
service area ranges from the northern Kenai Peninsula on the south, to Tyonek on
the west, to Whittier on the east and to Fort Richardson on the north.
Customers.
We directly serve approximately 71,800 meters. We have approximately
57,900 members (some members are served by more than one meter). Our customers
are primarily urban and suburban. The urban nature of our customer base means
that we have a relatively high customer density per line mile. Higher customer
density means that fixed costs can be spread over a greater number of customers.
As a result of lower average costs attributable to each customer, we benefit
from a greater stability in revenue, as compared to a less dense distribution
system in which each individual customer would have a more significant impact on
operating results. For the past five years no retail customer accounted for more
than 5% of our revenues.
Wholesale Customers
We are the principal supplier of power to MEA, Seward and Homer under
separate wholesale power contracts. For 2000, our wholesale power contracts
produced $47.4 million in revenues, representing 31% of our revenues and 43% of
our total kWh sales to customers.
MEA and Homer
We have two power sales contracts with AEG&T and each of MEA and Homer.
AEG&T is a generation and transmission cooperative formed by MEA and Homer.
Under each of these contracts, we sell power to AEG&T, which resells the power
to MEA and Homer. Each of MEA and Homer is obligated to pay us for the power
sold to AEG&T for its use if AEG&T does not pay.
Our contract for the benefit of MEA obligates MEA (through AEG&T) to
purchase all of its electric power and energy requirements from us.
Contractually, MEA has the right, on advance notice and subject to RCA approval,
to convert to a net requirements purchaser of power, and as such MEA would be
obligated to buy its needed power from us net of its power needs satisfied from
any of its own or AEG&T's resources. The notice period required for such
conversion may be up to five years, depending on which non-Chugach resources MEA
proposes to use to satisfy its power needs.
After conversion to a net requirements purchaser under the contract,
MEA cannot reduce the payment for power it purchases from us below a certain
minimum amount. If MEA converts to net requirements service, MEA will be
required to pay demand charges based upon the highest post-1985 historical
coincident peak on the MEA system. Therefore, we will continue to recover fixed
costs if MEA converts to net-requirements service. Also, our revenues from
energy sales to MEA would partially decline in proportion to the reduction in
the energy sold, but this decline would be offset to an extent by savings in the
variable costs associated with energy production.
MEA also has the right, on seven years advance notice and subject to
RCA approval, to convert to a take-or-pay purchase of a fixed amount of power,
also subject to minimum payment requirements associated with prior purchases.
The MEA contract is in effect through December 31, 2014. This contract does not
protect us against loss of load resulting from retail competition in MEA's
distribution service territory if retail competition is ever permitted in
Alaska. It is not possible at this time to estimate the potential impact on our
revenues that could result from such competition. See "Competition" above.
During the past several years, we have had numerous disputes and
engaged in substantial litigation with MEA regarding many aspects of our
contractual relationship with it. For example, in October 1998, the Board of
Directors of MEA announced that it had offered to acquire Chugach. Our Board of
Directors rejected the MEA acquisition proposal. MEA circulated a petition and
gathered a sufficient number of signatures from our members so that a special
meeting of our members was called for the purpose of considering MEA's proposal.
This meeting was held November 18, 1999, at which time our members
overwhelmingly rejected the MEA proposal. No further action regarding this offer
has been initiated by MEA. For a discussion of material pending litigation
between MEA and us, refer to Part I, Item 3 - "Legal Proceedings," of the Form
10-K filed by Chugach with respect to the annual report for the period ending
December 31, 2000.
Our contract for the benefit of Homer obligates Homer (through AEG&T)
to take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per
year. The Homer contract includes certain limitations on the costs that may be
included in our rates charged to Homer. The Homer contract expires on January 1,
2014. Homer's remaining resource requirements are provided by AEG&T's Nikiski
cogeneration facility and AEG&T's entitlement for power from the Bradley Lake
hydroelectric project for the benefit of Homer. In February 1999, we entered
into a dispatch agreement with AEG&T to operate the Nikiski unit as a Chugach
system resource. The agreement provides that, in addition to the energy that we
already sell to AEG&T and Homer, we will sell energy to AEG&T equal to Homer's
residual energy requirements less its allocated share of the Bradley Lake
project, up to a maximum of 320,000 MWh per year. A portion of the Nikiski unit
output may be dispatched for Homer needs in excess of the sum of our contract
demand plus Homer's share of energy from the Bradley Lake project. The dispatch
agreement will terminate in 2014 coincident with our power supply contract for
the benefit of Homer.
Seward
We currently provide nearly all the power needs of the City of
Seward. In February 1998, we entered into a new power sales agreement with
Seward that allows us to interrupt service to Seward up to 12 times per year and
provides for a 1/3 reduction in the demand charge (approximately $350,000
annually). This agreement expires September 1, 2001, but we have negotiated an
amendment to the agreement that will extend its term to January 31, 2006. The
amendment was fully executed on December 12, 2000, and subsequently filed for
approval with the RCA on February 5, 2001, and will be effective upon approval
by the RCA.
Economy Customers
Since 1988, we have sold nonfirm (economy) energy to Golden Valley
Electric Association ("GVEA") under an agreement that expires in 2008. Under the
agreement, we use available generating capacity in excess of our own needs to
produce electric energy for sale to GVEA, which uses that energy to serve its
own loads in place of more expensive energy that GVEA would otherwise generate
itself or purchase from other sources. We use gas purchased from Marathon Oil
Company ("Marathon") to produce energy for sale to GVEA, and we charge GVEA a
rate sufficient to recover the gas cost, the costs of incremental operations and
maintenance expense resulting from increased use of our generators for GVEA, and
an agreed-upon markup or margin for each kWh sold.
In 2000, the RCA approved an amendment to our agreement with GVEA and a
settlement of an inter-utility dispute involving it. As a result, the market for
economy energy sold to GVEA has now been divided into two parts. The larger part
continues to be governed by our agreement with GVEA, which assures us of
priority in sales of such energy to GVEA. In general, we are assured of selling
to GVEA two-thirds of the first 450,000,000 kWh of economy energy and 80% of the
excess over 450,000,000 kWh of economy energy that GVEA purchases each year if
we are capable of producing that energy. Remaining economy energy sales to GVEA
have now become the "Economy Energy Spot Market." Sales in the Economy Energy
Spot Market are completely competitive among potential sellers of economy energy
to GVEA. Neither we nor any other seller enjoys a contractual priority in making
such sales. One of those sellers, AML&P, is expected to dominate sales to GVEA
in the Economy Energy Spot Market for the immediate future, partly because AML&P
prices its gas at less than the Marathon gas on which we rely in making such
sales.
Load Forecasts
The following table sets forth our projected load forecasts for the
next five years:
Load (MWh) 2001 2002 2003 2004 2005
Retail....... 1,118,259 1,138,639 1,162,634 1,187,001 1,213,582
Wholesale.... 1,114,376 1,179,616 1,206,385 1,234,757 1,263,427
Economy...... 260,000 260,000 260,000 260,000 260,000
Losses....... 138,428 142,505 145,613 148,847 152,218
Total.....2,631,063 2,720,760 2,774,632 2,830,605 2,889,227
Sales are expected to increase over the next five years principally due
to economic growth in the service sector. Based on a study by University of
Alaska, our total energy requirements are expected to grow at an average
compounded annual rate of 2.6% from 2001 to 2005--retail sales at 2.1% and
wholesale sales at 3.2%.
Item 7 - Management's Discussion and Analysis
of Financial Condition and Results of Operations
Results Of Operations
Overview
Margins. We operate on a not-for-profit basis and, accordingly, seek
only to generate revenues sufficient to pay operating and maintenance costs, the
cost of purchased power, capital expenditures, depreciation and principal and
interest on our indebtedness and to provide for the establishment of reasonable
margins and reserves. Patronage capital, the retained margins of our members,
constitutes our principal equity.
Rate Regulation and Rates. Our rates are made up of two components:
"base rates" composed of demand and energy charges; and a "fuel surcharge" that
takes into account the rise and fall of fuel and purchased power costs. The RCA
regulates the rates paid by our wholesale and retail customers under base rates
and approves the quarterly fuel surcharge filing authorizing rate changes in the
fuel surcharge calculations.
Base Rates. We recover operating and maintenance and other non-fuel and
purchased power costs through our base rate established through a general rate
case process or through other normal RCA procedures. While the formal ratemaking
process typically takes nine months to one year, it is within the RCA's
authority to authorize, after a notice period, rate changes on an interim and
refundable basis. In addition, the RCA has been willing to open limited reviews
to resolve specific issues from which expeditious decisions can often be
generated.
Our base rates to our retail customers have not increased since 1994.
Our base rates to our wholesale customers have been subject to periodic
adjustment based on an order from the RCA. We will file a new general rate case
at the end of the second quarter of 2001 that, when adjudicated, may result in a
modest rate increase.
Our annual base rate changes, excluding fuel surcharges, for retail and
wholesale classes, for the years 1998 through 2000 were as follows:
2000 1999 1998
Retail 0.00% 0.00% 0.00%
Wholesale:
Homer (0.70%) (0.30%) 0.00%
MEA (0.80%) (3.80%) (0.20%)
Seward 0.00% 0.00% (15.00%)
The rate reductions to Matanuska Electric Association ("MEA") and Homer
result from the operation of a Settlement Agreement dated effective as of
November 21, 1996 as amended, among us, MEA, Homer and AEG&T (the "Settlement
Agreement"). The Settlement Agreement was designed to resolve a number of
ratemaking disputes and assure MEA and Homer that their base rates through 1999
would be no higher than those based on 1995 costs and would be reduced and
refunds given if our 1996, 1997 or 1998 test year costs to serve their needs
were significantly reduced.
The Settlement Agreement has not operated as we intended, because the
RCA has required us to make filings of our cost of service to facilitate
determination of over- or under-collection based on the 1996, 1997 and 1998 test
years. The rate reductions shown in the table for MEA and Homer in 1999 and 2000
relate to the first filing under the Settlement Agreement based on 1996 costs.
Our calculations based on 1996 costs indicated that a rate reduction was
required and that a refund was owed for the previous periods. We recorded
provisions for wholesale rate refunds that totaled $2,651,361 at December 31,
1999. Early in 2000, we issued refunds of $86,132 to Homer and $1,809,801 to MEA
that represented uncontested amounts owed consistent with the 1996 test year
filing.
In June 2000, the RCA issued a final order approving our 1996 test year
cost of service. As a result of this order, we issued additional refunds to MEA
and Homer in the amounts of $332,157 and $503,272, respectively, on July 25,
2000. Consistent with the Settlement Agreement, these refunds were based on
demand and energy purchases retroactive to January 1, 1997.
The rate reduction to Seward in 1998 was the result of a contract
renegotiation through which Seward moved from being a firm customer to an
interruptible customer. The rate reduction reflects the reduced cost of service
to serve Seward since the Seward load can be interrupted.
Fuel Surcharge. Fuel and purchased power costs are passed directly to
our wholesale and retail customers through the fuel surcharge. Changes in these
costs are due to fuel price adjustment mechanisms in our gas supply contracts
based on factors like inflation or other market conditions. We pass these costs
directly to our retail and wholesale customers, resulting in either a direct
increase or decrease to our system revenues. The fuel surcharge is approved on a
quarterly basis by the RCA. There are no limitations on fuel surcharge rate
changes. Increases in our fuel and purchased power costs result in increased
revenues while decreases in these costs result in lower revenues. Therefore,
revenue from the fuel surcharge normally does not impact margins.
The RCA ordered retroactive refunds in the approximate amount of $1.2
million because of alleged overcollection of fuel surcharges in 1995, 1996 and
1997. We appealed that finding to the Superior Court, which overturned the RCA's
ruling. While the RCA did not appeal the decision, our wholesale customer, MEA
did appeal that decision to the Alaska Supreme Court. MEA filed a brief in
support of its claim in January 2001. We filed our brief on March 14, 2001. No
hearing date has been set by the court.
Year ended December 31, 2000 compared to the years ended December 31,
1999 and 1998 Revenues
Operating revenues include sales of electric energy to retail,
wholesale and economy energy customers and other miscellaneous revenues. In
2000, operating revenues were $159 million, or 11%, higher than in 1999
primarily due to increased sales of economy energy to Golden Valley Electric
Association ("GVEA") following the shutdown of the Healy Clean Coal Project (the
"Healy Plant") in February 2000, higher recoverable fuel and purchased power
costs and increased revenue generated by our non-traditional business ventures.
In 1999, operating revenues were $143 million, or 0.57%, higher than in 1998.
Retail base rates for demand and energy did not change in 1999 while base rates
for demand and energy charged to MEA and Homer decreased slightly. Revenues and
power sold were as follows for the years ended December 31:
Year MWH Sold Operating Revenues
2000 2,409,088 $158,541,114
1999 2,190,253 $142,644,327
1998 2,055,963 $141,825,373
We make economy sales to GVEA. These sales commenced in 1988 and have
contributed to our growth in operating revenues. We do not take such economy
sales into consideration in our long-range resource planning process because
these sales are non-firm sales that depend on GVEA's need for additional energy
and our available generating capacity at the time. In 2000, 1999, and 1998,
economy sales to GVEA constituted approximately 5.03%, 0.79%, and 0.92%,
respectively, of our sales revenues. The increase in economy sales in 2000 from
1999 is due primarily to the shutdown of the Healy Plant, increasing the need
for GVEA to make economy purchases. The Healy Plant is a 50 megawatt
demonstration project in Healy, Alaska on the Alaska Intertie between Fairbanks
and Anchorage. Following the test period in 1998, GVEA asserted that the
demonstration was not successful. Litigation ensued and the Healy Plant has been
shutdown since that time pending further analysis of alternatives for its
operation. As a result, GVEA began buying economy energy from us at the time of
the Healy Plant shutdown.
Expenses
The major components of our operating expenses for the years ended
December 31, 2000, 1999 and 1998 were as follows:
2000 1999 1998
Power production $ 52,726,374 $ 40,301,607 $ 45,261,450
Purchased power 9,152,248 8,581,979 8,462,835
Transmission 3,828,630 3,813,438 2,771,652
Distribution 9,774,860 9,400,618 8,876,890
Consumer accounts 5,275,455 4,387,421 4,177,980
Sales expense 1,112,804 1,227,908 1,125,410
Administrative, general and
other 21,343,393 22,892,479 17,592,829
Depreciation 23,216,509 19,851,436 22,468,395
Total operating expenses $126,430,273 $110,456,886 $110,737,441
Power production expense increased in 2000 from 1999 by $12.4 million,
or 31%, due primarily to an increase in fuel expense from $29.6 million in 1999
to $42.5 million in 2000, which resulted from an average 40% increase in fuel
prices from 1999 to 2000. Power production expense decreased by $4.9 million, or
11%, in 1999 from 1998 due primarily to a decrease in fuel expense.
Purchased power costs increased from 1999 to 2000 by $570,000, or 7%.
We purchased more power from the Soldotna 1 unit and Anchorage Municipal Light
and Power ("AML&P") than anticipated due to avalanche damage to our transmission
lines early in the year, the limited availability of Beluga 3 and Beluga 6 units
during the summer months and an increase in economy energy purchases for GVEA.
Purchased power costs did not vary materially from 1998 to 1999.
Transmission expense did not vary materially from 1999 to 2000.
Transmission expense increased in 1999 from 1998 by $1 million, or 38%, due to
unanticipated transmission line repairs, Y2K preparation and testing and
overhead line maintenance activity as a result of outages early in 1999.
Distribution expense increased in 2000 from 1999 by $374,000, or 4%,
due primarily to an update in allocations of cost related to the information
services and garage clearing. This update shifted those costs from the general
and administrative category to the appropriate functional areas of the company.
Distribution expense increased in 1999 from 1998 by $525,000, or 6%, due
primarily to the increased outage activity that occurred early in 1999, which
resulted in increased labor costs.
Consumer accounts expense increased in 2000 from 1999 by $888,000 or
20%. This was due to less charges to costs for doubtful accounts in 1999 as
compared to 2000. In addition, the update to allocations of cost related to
information services caused an increase to this category in 2000. The increase
in consumer accounts in 1999 from 1998 was not material but resulted from
additional allocated marketing costs offset by less charges to costs for
doubtful accounts in 1999.
Sales expense did not vary materially in 2000, 1999 or 1998. The slight
variances are due to more or less allocated marketing cost resulting from
changes in the number of employees in the marketing department in these years.
Administrative, general and other expense decreased by $1.55 million,
or 6.8%, from 1999 to 2000. This decrease was a result of costs incurred in 1999
for outside counsel, consulting, advertising and internal labor costs associated
with an unsolicited MEA takeover attempt and resultant special meeting in 1999
and an update in allocations of cost related to information services in 2000.
General and administrative expense increased by $5.3 million, or 30%, from 1998
to 1999, primarily due to the costs associated with the MEA takeover attempt, an
increase in software amortization expense, increased maintenance costs of the
Y2K compliant software implementation completed in 1998, additional expenses
associated with our ancillary businesses and multiple insurance settlements paid
in 1999. In addition, general plant maintenance expenses were higher due to
multiple projects completed in 1999.
We use the composite method of depreciation. The increase in
depreciation expense from 1999 to 2000 was $3.4 million, or 17%, and was the
result of more transmission assets being placed in service in 2000. Depreciation
expense decreased in 1999 from 1998 by $2.6 million, or 12%, due to a change in
lives of general plant.
Interest on long term debt increased for the year ended December 31,
2000 over 1999, by $849,000, or 4%, due to higher amounts of outstanding debt.
Our outstanding indebtedness increased due to the issuance of $30 million in
bonds to CoBank, ACB ("CoBank") and to increased borrowing under the lines of
credit with CoBank and the National Rural Utilities Cooperative Finance
Corporation ("CFC") to fund the Beluga 6 re-powering project and the Cooper Lake
facility overhaul. Interest on short-term debt increased from 1999 to 2000 by
$912,000, or 91%, because of higher balances maintained and higher interest
rates. Our weighted average cost of total borrowings for 2000 was 8.06% compared
to 8.14% for 1999. Interest on long-term debt was slightly lower in 1999 than
1998 by $1 million, or 4%, due primarily to the refinancing of $34.9 million of
Series A Bonds due 2022 in the first quarter of 1999. Our weighted average cost
of total borrowings for 1998 was 8.43%. Net interest expense includes interest
on long-term debt and short-term debt, reduced by interest charged to
construction. Net interest expense is reduced by $1.54 million, $1.09 million
and $1.44 million in 1998, 1999 and 2000, respectively, which represents the net
effect of the amortization of the gain on refinancing offset by the amortization
of losses on refinancing and transaction costs.
Margins
Our margins for the years ended December 31, 2000, 1999 and 1998, were
as follows:
Net Operating Margins Nonoperating Margins Assignable Margins
2000 $ 7,392,551 $ 2,287,227 $ 9,679,778
1999 $ 8,052,060 $ 1,615,374 $ 9,667,434
1998 $ 6,619,263 $ 2,111,141 $ 8,730,404
Nonoperating margins include interest income, allowance for funds used
during construction, capital credits and patronage capital allocations.
Nonoperating margins increased in 2000 over 1999 by $672,000 or 42%. This was
due to an allowance for funds used during construction based on higher
construction work in progress balances during the year, increased allocations of
patronage capital from CoBank, and higher interest earnings in 2000 as a result
of increased short-term investment balances. Nonoperating margins decreased in
1999 over 1998, by $496,000, or 23%. The primary contributor to the decrease
from 1998 is the gain on the sale of a surplus compressor rotor to GVEA in 1998.
The variance is also due in part to higher-than-anticipated patronage capital
from CoBank but is offset by a decrease in interest earnings in 1999 as a result
of decreased short-term investment balances.
Patronage Capital (Equity)
Our patronage capital and total equity have shown steady growth. The
following table summarizes our patronage capital and total equity position since
1998:
2000 1999 1998
Patronage capital at beginning
of year $117,335,481 $109,622,996 $104,800,092
Retirement of capital credits
and estate payments (4,090,006) (1,954,949) (3,907,500)
Assignable margins 9,679,778 9,667,434 8,730,404
Patronage capital at end of year 122,925,253 117,335,481 109,622,996
Other equity 5,890,087 5,189,164 4,400,300
Total equity at end of year $128,815,340 $122,524,645 $114,023,296
In furtherance of our operations as a cooperative, we credit to our
members all amounts received from them for the furnishing of electricity in
excess of our operating costs, expenses and provision for reasonable reserves.
These excess amounts (i.e., assignable margins) are considered capital furnished
by the members, and are credited to their accounts and held by us until such
future time as they are retired and returned without interest. Approval of
actual capital credit retirements is at the discretion of our Board of
Directors. We currently have a practice of retiring patronage capital on a
first-in, first-out basis for retail customers. At December 31, 2000, we retired
all retail capital credits attributable to margins earned in periods prior to
1984 and approximately 19% of 1985 retail capital credits. Prior to 2000,
wholesale capital credits had been retired on a 10-year cycle pursuant to an
Equity Management Plan Settlement Agreement despite its expiration in 1995.
However, in 2000, there was no wholesale retirement as we implemented a plan to
return the capital credits of wholesale and retail customers on a 15-year
rotation.
The 1991 Indenture includes a covenant restricting the distribution of
patronage capital to members. We cannot distribute patronage capital to members
if 1) an event of default exists or 2) the aggregate amount of patronage capital
distributions after September 15, 1991, exceeds the sum of $7,000,000 plus 35%
of the aggregate assignable margins earned after December 31, 1990. At December
31, 2000, we were permitted to distribute $4.14 million to our members under the
1991 Indenture under this formula.
We also retire our patronage credits through annual payments to our
members. The table below sets forth a five-year summary of anticipated capital
credit retirements:
Year Ending Wholesale Retail Total
2001 $ 0 $3,500,000 $3,500,000
2002 0 3,500,000 3,500,000
2003 0 3,500,000 3,500,000
2004 1,359,000 3,500,000 4,859,000
2005 1,109,000 3,500,000 4,609,000
Times Interest Earned Ratio (TIER)
Alaska electric cooperatives generally set rates on the basis of TIER.
TIER is determined by dividing the sum of assignable margins plus long-term
interest expense (excluding capitalized interest) by long-term interest expense.
Beginning in 1989, our Board of Directors approved an Equity Management Plan
that established a schedule for building our equity. Since then we have managed
our business with a view toward achieving a TIER of 1.25 or greater. We achieved
TIERs for the past five years as follows:
Period TIER
2000 1.39
1999 1.40
1998 1.35
1997 1.30
1996 1.39
Sale of a Segment
As of March 20, 2001, we sold to GCI Communication Corporation the bulk
of our internet service provider assets related to dial-up services (excluding
DSL services). The aggregate purchase price was $759,049 at closing, with a
potential for additional amounts, not to exceed $85,850, based on the number of
subscriber accounts retained during the ninety-day transition period following
closing. We are also to receive service fees for technical and other transition
services during such period billed on a time-and-materials basis. The
transaction will result in a minimal gain.
Changes In Financial Condition
Total assets increased by $21.4 million, or 4%, from December 31, 1999,
to December 31, 2000. The increase was due to an increase in electric plant in
service related to the Beluga 6 unit re-powering, the U.S. Postal Service fuel
cell project and various distribution projects. This, however, was offset by a
decrease in cash and cash equivalents caused by the funding requirements imposed
by the above-mentioned projects and a decrease in materials and supplies caused
by the writing off of spare generation parts from inventory. There was an
increase in accounts receivable caused by the under-collection of the fuel
surcharge in the fourth quarter of 2000. Changes to total liabilities include
the increase in notes payable due to borrowing activity during the year. There
was also an increase in accrued salaries, wages and benefits due to overall
increases in company-wide benefits, as well as increases associated with new
contracts with the IBEW. Additionally, the fuel liability increased due to
rising fuel prices.
Liquidity And Capital Resources
We satisfy our operational and capital cash requirements primarily
through internally-generated funds, a $50 million line of credit from CFC and a
$35 million line of credit with CoBank. At December 31, 2000, there was $5
million outstanding with CFC. An additional $5 million was borrowed in January
2001, and an additional $10 million was borrowed in March 2001. The current
outstanding balance as of March 2001 is $20 million. This line of credit bears
interest at a variable rate, which was 8.550% as of December 31, 2000, and is
currently 7.80% as of April 6, 2001. As of December 31, 2000, $35 million was
outstanding under the CoBank line of credit. This line of credit bears interest
at a variable rate, which was 8.20% as of December 31, 2000, and is currently
7.55% as of April 6, 2001. Additionally, we have negotiated a supplemental
indenture with CFC authorizing a series of bonds in an amount of up to $80
million. At December 31, 2000, we had issued no bonds to CFC.
On March 22, 2001, Chugach filed a Registration Statement, Form S-1,
with the Securities and Exchange Commission in anticipation of Chugach's $150
million public bond offering.
Principal maturities and sinking fund payments of our outstanding
indebtedness at December 31, 2000 are set forth below:
Year Ending
December 31 Sinking Fund Requirements Principal maturities Total
2001 $ 6,097,000 $ 333,350 $ 6,430,350
2002 5,232,000 77,677,944 82,909,944
2003 5,041,000 865,821 5,906,821
2004 5,502,000 945,000 6,447,000
2005 6,005,000 11,031,000 17,036,000
Thereafter 147,762,000 52,158,180 199,920,180
During 2000, we spent approximately $46.7 million on capital
construction projects, which includes interest capitalized during construction.
We develop five-year work plans that are updated every year. Our capital
improvement requirements are based on long-range plans and other supporting
studies and are executed through a five-year construction work plan. Set forth
below is an estimate of capital expenditures for the years 2001 through 2005:
2001 $36.0 million
2002 $42.5 million
2003 $40.2 million
2004 $40.0 million
2005 $40.1 million
We are a party to a Treasury rate-lock with respect to the refinancing
of a portion of the 1991 Series A Bonds. The settlement date of this contract is
March 15, 2002. At December 31, 2000, the Treasury-rate lock agreement had an
estimated value of ($8.6) million. At April 6, 2001, the agreement had an
estimated value of ($12.0) million. See "Quantitative and Qualitative
Disclosures About Market Risk--Interest Rate Risk."
We expect that cash flows from operations and external funding sources
will be sufficient to cover operational and capital funding requirements in 2001
and thereafter.
Changes in Accounting Principles
We were required to adopt SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS No. 138, effective
January 1, 2001. This new standard requires all derivative financial instruments
to be reflected on the balance sheet. As of January 1, 2001, we have established
a regulatory asset for $8.6 million and a liability for the same amount. The
regulatory asset and liability will be adjusted for changes in the fair value of
a Treasury rate-lock agreement entered into by us. See "Quantitative and
Qualitative Disclosures about Market Risk - Interest Rate Risk." Management
believes it is probable the regulatory asset will be recovered through rates.
Item 7A - Quantitative and Qualitative Disclosures
About Market Risk
We are exposed to a variety of risks, including changes in interest
rates and changes in commodity prices due to repricing mechanisms inherent in
gas supply contracts. In the normal course of our business, we manage our
exposure to these risks as described below. We do not engage in trading market
risk-sensitive instruments for speculative purposes.
Interest Rate Risk
As of December 31, 2000, except for two bonds issued to CoBank carrying
variable interest rates that are periodically re-priced, all of our other
outstanding long-term borrowings were at fixed interest rates with varying
maturity dates. The following table provides information regarding cash flows
for principal payments on total debt by maturity date (dollars in thousands) as
of December 31, 2000 and 1999:
2000
Fair
Total Debt* 2001 2002 2003 2004 2005 Thereafter Total Value
Fixed rate $6,430 $10,410 $5,907 $6,447 $17,036 $199,920 $246,150 $262,655
Average
interest rate 8.13% 6.90% 8.62% 8.62% 8.12% 8.22% 8.17%
Variable rate $40,000 $72,500 $0 $0 $0 $0 $112,500 $112,500
Average
interest rate 8.24% 8.20% -- -- -- -- 8.22%
* Includes current portion
1999
Fair
Total Debt* 2000 2001 2002 2003 2004 Thereafter Total Value
Fixed rate $6,372 $6,430 $10,410 $5,907 $6,447 $235,456 $271,023 $282,034
Average
interest rate 8.12% 8.13% 6.90% 8.62% 8.62% 7.95% 7.95%
Variable rate $0 $0 $72,500 $0 $0 $0 $72,500 $72,500
Average
interest rate -- -- 6.87% -- -- -- 6.87%
* Includes current portion
We are exposed to market risk from changes in interest rates. A 100
basis-point change (up or down) would increase or decrease our interest expense
by approximately $1,125,000, based on $112.5 million of variable debt
outstanding at December 31, 2000. The CoBank and CFC lines of credit, under
which we currently have $55 million in short-term debt outstanding, bear
interest at variable rates.
As of December 31, 2000, the aggregate principal amount of outstanding
1991 Series A Bonds due 2022 was $164,310,000. The 1991 Series A Bonds due 2022
are not callable until March 15, 2002. To manage interest rate exposure for
refinancing of these bonds on their first available call date, March 15, 2002,
we entered into a Treasury rate-lock transaction with Lehman Brothers Financial
Products Inc. ("Lehman Brothers"). Under the Treasury rate-lock contract, we
will receive a lump-sum payment from Lehman Brothers on March 15, 2002, if the
yield on 10- or 30-year Treasury bonds as of mid-February 2002, exceeds a
specified target level (5.653% and 5.838%, respectively). Conversely, we will on
the same date be required to make a payment to Lehman Brothers if the yield on
the 10- or 30-year Treasury bonds falls below their stated target yields. In
each case, the amount of the payment will increase as the difference between the
actual yield and the target yield widens. For each basis point (0.01% per annum)
by which the yield on 10-year or 30-year Treasury bonds deviates from the stated
target level we will receive (if the prevailing Treasury yield exceeds the
target yield) or make (if the prevailing Treasury yield falls short of the
target yield) a payment equal to the product obtained by multiplying (i) the
difference between the prevailing and target yields (expressed in basis points)
by (ii) the changes in the prices of $196 million (in the case of 10-year
Treasury bonds) and $18.7 million (in the case of the 30-year Treasury bonds) of
Treasury bonds, given a one-basis-point change in their respective yields
(determined with reference to the Bloomberg Financial Markets Government Yield
Analysis Page). In this way, we intend that higher interest costs resulting from
any increases in market interest rates between the date of the rate-lock
contract and the refinancing of our long-term debt would be mitigated by a
lump-sum, up-front payment to us at the time of the refinancing. Conversely, any
savings from decreases in interest rates during the same period would be reduced
by a payment by us to the rate-lock counterparty. At December 31, 2000 and 1999,
the Treasury rate lock agreement had an estimated value of approximately
$(8,600,000) and $13,000,000, respectively. The decrease in estimated value is
due to the decline on the yield on the 10-year and 30-year Treasury bonds. A 10
basis-point change (up or down) in the prevailing yield on both 10-year and
30-year Treasury bonds would change the value of the rate-lock agreement (up or
down) by approximately $1,800,000.
Commodity Price Risk
Our gas contracts provide for adjustments to gas prices based on
fluctuations of certain commodity prices and indices. Because purchased power
costs are passed directly to our wholesale and retail customers through a fuel
surcharge, fluctuations in the price paid for gas pursuant to long-term gas
supply contracts does not normally impact margins. The fuel surcharge mechanism
mitigates the commodity price risk related to market fluctuations in the price
of purchased power.
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 April 9, 2001.
CHUGACH ELECTRIC ASSOCIATION, INC.
By: /s/ Eugene N. Bjornstad
Eugene N. Bjornstad
General Manager
Date: April 9, 2001
By: /s/ Evan J. Griffith
Evan J. Griffith
Executive Manager, Finance & Energy Supply
(Principal Financial Officer)
Date: April 9, 2001