PROSPECTUS
$150,000,000
CHUGACH ELECTRIC ASSOCIATION, INC.
2001 Series A Bonds Due 2011
CHUGACH
The 2001 Series A Bonds will mature on March 15, 2011 and will bear
interest at 6.55% per annum. We will pay interest on the 2001 Series A Bonds
semi-annually on March 15 and September 15 of each year commencing with
September 15, 2001. We may not redeem the 2001 Series A Bonds prior to maturity.
Payment of the 2001 Series A Bonds initially will be secured by a first
lien on substantially all of our tangible and some intangible properties. The
first lien will be automatically released when all bonds issued by us prior to
the issue date of the 2001 Series A Bonds cease to be outstanding or their
holders consent to conversion to unsecured status. Thereafter, the 2001 Series A
Bonds will be unsecured obligations, ranking equally with our other unsecured
and unsubordinated obligations.
The scheduled payment of the principal and interest on the 2001 Series
A Bonds, when due, will be insured by an insurance policy to be issued
concurrently with the delivery of the 2001 Series A Bonds by MBIA Insurance
Corporation. See "Bond Insurance."
MBIA
Underwriting Discounts
Price to Public(1) and Commissions Proceeds to Chugach(2)
Per Bond............ 99.835% 0.909% 98.926%
Total............... $149,752,500 $1,363,500 $148,389,000
.........(1) Plus accrued interest from April 17, 2001, if any.
.........(2) Less expenses estimated to be $1,515,000.
The 2001 Series A Bonds are offered by the underwriter subject to certain
conditions and subject to prior sale and when, as and if issued and accepted by
the underwriter. We expect that the 2001 Series A Bonds will be available for
delivery in New York, New York in book-entry form on or about April 17, 2001
through the facilities of The Depository Trust Company against payment therefor
in immediately available funds.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful and complete. Any representation to the contrary is a
criminal offense.
JPMorgan
April 11, 2001
You should rely only on the information contained in this prospectus.
We have not authorized anyone to provide you with information different from
that contained in this prospectus. We are offering to sell, and seeking offers
to buy, the 2001 Series A Bonds only in jurisdictions where offers and sales are
permitted. The information contained in this prospectus is accurate only as of
the date of this prospectus, regardless of the time of delivery of this
prospectus or of any sale of our 2001 Series A Bonds. In this prospectus, the
words "we," "us," and "our" refer to Chugach Electric Association, Inc. unless
the context indicates otherwise.
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TABLE OF CONTENTS
Page
PROSPECTUS SUMMARY...............................................................................................3
USE OF PROCEEDS..................................................................................................7
SELECTED FINANCIAL DATA..........................................................................................8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS....................................................................9
BUSINESS........................................................................................................19
MANAGEMENT......................................................................................................31
BOND INSURANCE..................................................................................................35
DESCRIPTION OF THE BONDS........................................................................................37
CERTAIN TAX MATTERS.............................................................................................46
UNDERWRITING....................................................................................................47
LEGAL OPINIONS..................................................................................................47
EXPERTS.........................................................................................................48
WHERE TO FIND ADDITIONAL INFORMATION ABOUT CHUGACH..............................................................48
INDEX TO FINANCIAL STATEMENTS..................................................................................F-1
APPENDIX A: Specimen of Insurer's Policy.......................................................................A-1
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The Chugach logo is a trademark of Chugach Electric Association, Inc.
All other trademarks or tradenames referred to in this prospectus are the
property of their respective owners.
Information contained on our web site does not constitute part of this
prospectus.
Until May 21, 2001, all dealers that effect transactions in our 2001
Series A Bonds, whether or not participating in this offering, may be required
to deliver a prospectus. This requirement is in addition to the dealers'
obligation to deliver a prospectus when acting as underwriters and with respect
to their unsold allotments or subscriptions.
2
SUMMARY
The following summary contains information about our company, the
offering and the terms of the 2001 Series A Bonds that we believe is important.
You should read the entire prospectus, including the financial statements and
the notes to those financial statements, for a complete understanding of our
business and the offering. This prospectus contains forward-looking statements
based on our current expectations, assumptions, estimates and projections about
us and our industry. These forward-looking statements involve risks and
uncertainties. Our actual results could differ materially from those anticipated
in these forward-looking statements as a result of certain factors, which are
more fully described elsewhere in this prospectus. We undertake no obligation to
update publicly any forward-looking statements for any reason, even if new
information becomes available or other events occur in the future, except as
required by law.
Explanation of Accounting Terms
We are organized as a cooperative. As such, we use different accounting
terminology than stockholder-owned corporations. In this prospectus, when we
refer to assignable margins for a period, we mean revenues in excess of costs
for the period. When we refer to patronage capital we mean assignable margins we
have not distributed to our members. Patronage capital constitutes our principal
equity and is assigned to each member on the basis of the volume of purchases
from us.
Terms of the 2001 Series A Bonds
Amount Offered...................... $150,000,000 principal amount of 2001
Series A Bonds due 2011.
Interest Payment Dates.............. March 15 and September 15, commencing
September 15, 2001.
Redemption.......................... We may not redeem the 2001 Series A
Bonds at any time prior to maturity.
Security for the Bonds.............. The 2001 Series A Bonds initially will
be secured by a first lien on
substantially all of our tangible and
some of our intangible properties and
assets, including generation,
transmission and distribution
properties, with certain exceptions
set forth in the Indenture of Trust,
dated September 15, 1991, as amended,
between Chugach and U.S. Bank Trust
National Association as trustee (the
"Existing Indenture"), and subject to
certain permitted encumbrances set
forth in the Existing Indenture. The
first lien will be automatically
released on the date on which all
bonds issued under the Existing
Indenture prior to the 2001 Series A
Bonds cease to be outstanding or their
holders consent to conversion to
unsecured status (the "Release Date").
We do not anticipate that the Release
Date will occur prior to March 15,
2002.
On the Release Date, the Amended and
Restated Indenture dated April 1,
2001, between us and U.S. Bank Trust
National Association, as trustee (the
"Amended Indenture"), will become
effective and replace the Existing
Indenture. On the Release Date, the
2001 Series A Bonds will become
general unsecured obligations and will
rank equally and ratably with all our
other unsecured and unsubordinated
obligations. See "Description of the
3
Bonds - Security for Payment of the
Obligations Prior to Release Date;
Conversion to Unsecured Obligations on
Release Date."
Under the Amended Indenture, we are
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),
except that we may incur secured
indebtedness in an amount not to
exceed $5,000,000.
Bond Insurance................. MBIA Insurance Corporation has issued
a commitment to provide an insurance
policy providing for the payment of
principal and interest on the 2001
Series A Bonds when due. As an insurer
of the 2001 Series A Bonds, MBIA (and
not the holders of 2001 Series A
Bonds) will be considered the holder
of the 2001 Series A Bonds for the
purpose of approving supplemental
indentures or other amendments to the
Existing Indenture or Amended
Indenture, giving any other approval
consent or notice to effect any
waiver, exercising any remedies, and
taking any other action that could be
taken by the holders of 2001 Series A
Bonds in the absence of such bond
insurance. See "Bond Insurance";
"Description of the Bonds--Rights of
Insurer."
Additional Bonds............... Prior to the Release Date, subject to
meeting certain interest coverage
tests, we may issue additional bonds
from time-to-time against the cost of
certain property acquisitions, the
principal amount of retired or
defeased bonds and deposits of cash
with the trustee. After the Release
Date, we may issue additional
obligations subject only to meeting
certain interest coverage tests. See
"Description of the Bonds - Additional
Obligations."
Rate Covenant................... The Existing Indenture requires us,
subject to any necessary regulatory
approval, to establish and collect
rates reasonably expected to yield
margins for interest equal to at least
1.20 times total interest expense.
Margins for interest are defined in
the Existing Indenture as our
assignable margins plus total interest
expense and income tax accruals.
The Amended Indenture will require us,
subject to any necessary regulatory
approval, to establish and collect
rates reasonably expected to yield
margins for interest equal to at least
1.10 times total interest expense.
Margins for interest are defined in
the Amended Indenture as our
assignable margins plus total interest
expense (other than from subordinated
debt), income tax accruals and
non-recurring charges. See
"Description of the Bonds - Rate
Covenant."
Limitations on Distributions to
Members........................ The Existing Indenture prohibits us
from making any distribution, payment
or retirement of patronage capital to
our customers if an event of default
under the Existing Indenture then
exists. Otherwise we are permitted to
make distributions to our members
after December 31, 1990 in the
aggregate amount of $7 million plus 35
4
percent of the aggregate assignable
margins earned after December 31,
1990. This restriction does not apply
if, after the distribution, payment or
retirement, our aggregate equities and
margins as of the end of the
immediately preceding fiscal quarter
would be equal to at least 45% of our
total liabilities and equities and
margins. At December 31, 2000, we
could have distributed $4.14 million
to our members under this formula. We
have not made any distributions
subsequent to December 31, 2000.
The Amended Indenture will prohibit us
from making any distribution, payment
or retirement of patronage capital to
our customers if an event of default
under the Amended Indenture then
exists. Otherwise, we may make
distributions to our members in each
year equal to the lesser of 5% of our
patronage capital or 50% of assignable
margins for the prior fiscal year.
This restriction will not apply if,
after the distribution, payment or
retirement, our aggregate equities and
margins as of the end of the
immediately preceding fiscal quarter
would be equal to at least 30% of our
total liabilities and equities and
margins. See "Description of the Bonds
- Limitation on Distributions to
Members."
Reporting Obligations............... We do not intend to register the 2001
Series A Bonds under Section 12(b) of
the Securities Exchange Act of 1934,
as amended. We will, however,
initially be subject to the reporting
requirements of Section 15(d) of the
Securities Exchange Act. The Existing
Indenture and the Amended Indenture
require us to continue reporting under
the Securities Exchange Act for so
long as any of the 2001 Series A Bonds
are outstanding.
Form and Denomination............... The 2001 Series A Bonds will be
evidenced by one or more global
certificates in fully registered form
without coupons, deposited with a
custodian for and registered in the
name of a nominee of The Depositary
Trust Company. Except as described in
this prospectus, beneficial interests
in the global certificates will be
shown on, and transfers of these
beneficial interests will be effected
only through, records maintained by
The Depository Trust Company and its
direct and indirect participants. See
"Description Of The Bonds - Book-Entry
System; Exchangeability."
Market for 2001 SeriesA
Bonds............................. We do not intend to list the 2001
Series A Bonds on any securities
exchange nor have them quoted on the
National Association of Securities
Dealers Automated Quotation System. As
a result, there may not be a secondary
market for the 2001 Series A Bonds.
J.P. Morgan Securities Inc. intends,
but is not obligated, to make a market
in the 2001 Series A Bonds. See
"Underwriting."
5
Our Company and Business
Chugach Electric Association, Inc., is the largest electric utility in
Alaska. We provide electricity on a regular basis, either directly or through
our wholesale and economy-energy sales, to approximately two-thirds of all
electric customers in Alaska. We have approximately 57,900 directly served
retail customers and also regularly supply capacity and energy to three
wholesale customers and economy energy to one additional customer. We also
provide electricity periodically to Anchorage Municipal Light & Power.
Our certificated service area extends from Anchorage (except certain
downtown and residential areas of Anchorage) to the upper Kenai Peninsula and
from Whittier on Prince William Sound to Tyonek on the west side of Cook Inlet.
We also provide power to Alaskans from Homer to Fairbanks through sales to our
wholesale customers. For the year ended December 31, 2000, approximately 64% of
our revenues were from sales to our directly served retail customers,
approximately 31% were from sales of firm power to our three wholesale customers
and approximately 5% were from economy sales.
We have approximately 511 megawatts of installed generating capacity
provided by 17 generating units at our four wholly owned power plants: Beluga
Power Plant, Bernice Lake Power Plant, International Generating Station and
Cooper Lake Hydroelectric Plant, and our 30% share of the Eklutna Hydroelectric
Project. In addition, we have purchase rights to 30.4% (27.4 megawatts) of the
Bradley Lake Hydroelectric Project and we pool the output of the Nikiski
cogeneration facility on the Kenai Peninsula, a nominally rated 40 megawatt
generation unit.
Of our 511 megawatts of owned generating capacity, approximately 482
megawatts are generated from 12 gas-fired combustion turbine units and one
waste-heat steam turbine unit and approximately 29 megawatts are generated from
hydroelectric power from four turbine units. Approximately 96% of our energy was
generated from natural gas in 2000, and of that amount, 85% was from our Beluga
Power Plant units. We purchase natural gas from suppliers under long-term
natural gas purchase contracts.
We have the right to provide retail electric service in the
certificated service area exclusively assigned to us by the Regulatory
Commission of Alaska ("RCA"). The RCA must approve the rates at which we sell
electricity. We also recover increases in fuel and purchased power costs through
an automatic quarterly fuel cost adjustment to our rates, which is not subject
to any rate increase limits. Under Alaska law, financial covenants in the 2001
Series A Bonds and the Existing and Amended Indenture are valid and enforceable,
and rates set by the RCA must be adequate to meet those covenants.
As part of a settlement of disputes over rate adjustments with our
wholesale customers, we agreed that our demand and energy rate pricing for
wholesale customers would not exceed 1995 levels at least through 1999 and could
be reduced if existing rates provide returns significantly higher than those
specified in the settlement. 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. We and MEA have each
filed petitions for reconsideration of this order. The 1998 test year cost
calculation is currently being reviewed by the RCA. Our initial calculations
show no rate reduction or refund is indicated based on the 1998 test year. We
anticipate that we will file a new general rate case at the end of the second
quarter of 2001.
We were organized as an Alaska electric generation, transmission and
distribution cooperative in 1948. As with electric cooperatives generally, we
operate on a not-for-profit basis. As a cooperative, we design our rates on a
cost-of-service basis that historically allows us to recover our operating and
maintenance costs and expenses; debt service; costs of repairs, replacements,
6
and renewals; and costs for that portion of capital additions not funded by
borrowings. We do not design rates to produce a return on equity.
We are exempt from federal income taxation under Section 501(a) of the
Internal Revenue Code of 1986, as amended, as an organization described in
501(c)(12) of the Code.
Our principal office is located at 5601 Minnesota Drive, Anchorage,
Alaska 99519-6300, and our telephone number is (907) 563-7494.
USE OF PROCEEDS
We will apply the net proceeds of this offering, estimated to be
$146,874,000 after payment of underwriting discounts and offering expenses, to
retire indebtedness outstanding under existing lines of credit and outstanding
bonds, for capital expenditures and for general working capital. The lines of
credit that we intend to retire have an aggregate outstanding principal balance
of $55,000,000, are renewable annually and bear interest at variable annual
rates ranging from 8.20% to 8.55% as of December 31, 2000, and 7.55% to 7.80% as
of April 6, 2001. The bonds that we intend to retire have an aggregate
outstanding principal balance of $72,500,000, mature in 2002 and bear interest
at a variable rate that is 8.20% as of December 31, 2000 and 7.55% as of April
6, 2001.
7
SELECTED FINANCIAL DATA
The selected financial data presented in the table below for and as of
the end of each year in the five-year period ended December 31, 2000 are derived
from our audited financial statements. The balance sheets of Chugach as of
December 31, 2000 and 1999, 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, 2000 and the report of KPMG LLP thereon are included
elsewhere in this prospectus. The information contained in this table is
qualified entirely by reference to the financial statements and notes thereto
included in this prospectus.
Years ended December 31,
-------------------------------------------------------------------
Statements of Operations Data: 2000 1999 1998 1997 1996
---------- ---------- ---------- ----------- ----------
(in thousands)
Operating revenues...................... $ 158,541 $ 142,644 $ 141,825 $ 143,948 $ 134,877
Operating expenses...................... (126,430) (110,457) (110,737) (113,071) (100,914)
Interest expense........................ (24,718) (24,135) (24,469) (25,085) (25,349)
---------- ---------- ---------- ----------- ----------
Net operating margins.............. 7,393 8,052 6,619 5,792 8,614
Non operating margins................... 2,287 1,615 2,111 1,762 1,217
---------- ---------- ---------- ----------- ----------
Assignable margins................. $ 9,680 $ 9,667 $ 8,730 $ 7,554 $ 9,831
========== ========== ========== =========== ==========
Ratio of earnings to fixed charges(1)... 1.360 1.385 1.345 1.294 1.379
Years ended December 31,
-------------------------------------------------------------------
Balance Sheet Data: 2000 1999 1998 1997 1996
---------- ---------- ---------- ----------- ----------
Assets: (in thousands)
Plant net:
In service....................... $427,127 $398,545 $386,235 $393,229 $400,053
Construction work in progress.... 42,028 47,257 30,406 24,664 19,827
---------- ---------- ---------- ----------- ----------
Electric plant, net............ 469,155 445,802 416,641 417,893 419,880
Other assets....................... 70,591 72,554 64,450 67,674 62,608
---------- ---------- ---------- ----------- ----------
Total assets................... $539,746 $518,356 $481,091 $485,567 $482,488
========== ========== ========== =========== ==========
Liabilities:
Current liabilities................ $ 77,286 $ 33,970 $ 33,081 $ 34,461 $ 36,686
Deferred credits................... 21,425 24,711 28,069 29,979 33,418
Long-term debt (excluding 312,220 337,150 305,918 312,007 307,906
current portion).................
Equities and margins............... 128,815 122,525 114,023 109,120 104,478
---------- ---------- ---------- ----------- ----------
Total liabilities and equities... $539,746 $518,356 $481,091 $485,567 $482,488
========== ========== ========== =========== ==========
1 For purposes of this ratio, earnings consist of earnings plus fixed
charges. Fixed charges consist of interest expense on all indebtedness,
including capitalized interest. As a tax-exempt organization, we do not pay
federal income tax. The ratio of earnings to fixed charges for Chugach is
less than that for some investor-owned utilities because we do not seek a
return on equity in establishing our rates.
8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Caution Regarding Forward Looking Statements
Statements in this prospectus 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 prospectus 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. 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%)
9
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.
10
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
11
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
12
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
13
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 Existing 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 Existing Indenture under this formula. The Amended Indenture will
prohibit us from making any distribution, payment or retirement of patronage
capital to our customers if an event of default under the Amended Indenture then
exists. Otherwise, we may make distributions to our members in each year equal
to the lesser of 5% of our patronage capital or 50% of assignable margins for
the prior fiscal year. This restriction will not apply if, after the
distribution, payment or retirement, our aggregate equities and margins as of
the end of the immediately preceding fiscal quarter would be equal to at least
30% of our total liabilities and equities. See "Description of the
Bonds--Limitation on Distributions to Members."
We also retire our patronage credits through annual payments to our
members. The table below sets forth a five-year summary of anticipated capital
credit retirements:
Year Ending 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. Due to
increased depreciation expense in 2001 and lower than anticipated revenues in
the first quarter of 2001 because of warmer weather in Alaska, it is anticipated
that the TIER for 2001 will be in the range of 1.20 to 1.25. We anticipate
filing a rate increase in a general rate case to be filed in June 2001, which if
approved could increase our achieved TIER in future periods. 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
14
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 International Brotherhood of Electrical Workers ("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. This line of
credit bears interest at a variable rate, which was 8.55% as of December 31,
2000, and is 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 7.55% as of
April 6, 2001. It is our intention to repay both these lines of credit with the
proceeds from this offering. 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.
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
15
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.
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:
16
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. CoBank Bonds 6 and 7, bearing variable
interest rates, in the aggregate amount of $72.5 million will be retired with a
portion of the proceeds from the 2001 Series A Bonds. The CoBank and CFC lines
of credit, under which we currently have $55 million in short-term debt
outstanding, bear interest at variable rates. The CoBank and CFC lines of credit
will also be repaid with a portion of the proceeds from the sale of the 2001
Series A Bonds.
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
17
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.
18
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, MEA, Homer and
Seward. In addition, on a periodic basis, we provide electricity to 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 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
19
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 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.
20
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 Existing 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. See "Description of Bonds - Rate Covenant." The
authorized rate-setting 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. On the Release Date, the Amended Indenture will supersede the
Existing Indenture and will require us to set rates designed to yield margins
for interest equal to at least 1.10 times total interest expense.
21
Under Alaska law, a cooperative utility that is negotiating to enter
into a mortgage or other debt instrument that provides for a TIER greater than
the ratio the commission most recently approved for that cooperative must submit
the mortgage or debt instrument to the RCA before the instrument takes effect.
However, the rate covenant contained in the Amended Indenture will impose no
greater TIER requirement than does the rate covenant contained in the Existing
Indenture. We do not expect the requirements of either the Existing Indenture or
the Amended Indenture to exceed the TIER most recently approved for us by the
RCA.
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
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.
22
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, see "Legal Proceedings."
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
23
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 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
24
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%.
Properties
General
We have 511 megawatts of installed capacity consisting of 17 generating
units at five power plants. These include 368.1 megawatts of operating capacity
at the Beluga facility on the west side of Cook Inlet; 67.5 megawatts of power
at the Bernice Lake facility on the Kenai Peninsula; 46.7 megawatts of power at
International Generating Station in Anchorage; and 17.2 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 plant generating units owned
jointly 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 Homer and dispatched by us.
The Beluga, Bernice Lake and International facilities are all fueled by natural
gas. We own our offices and headquarters, located adjacent to our International
Generating Station in Anchorage. Warehouse space for some generation,
transmission and distribution inventory (including a small amount of office
space) is leased from an independent party.
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 originally leased from Chevron
Oil Company and now owned by Homer, and our generating plant at Cooper Lake. The
Cooper Lake facility is located on federal land pursuant to a major project
license granted to us by the Federal Power Commission in 1957. The Bernice Lake
ground lease expires in 2011 and the federal license for the Cooper Lake
facility expires in 2007. We have no reason to believe that we will not be able
to renew the federal license or the Bernice Lake facility ground lease if
desirable.
In 1997, we acquired a 30% interest in the Eklutna Hydroelectric
Project. The plant is located on federal land pursuant to a United States Bureau
of Land Management right-of-way grant issued in October 1997.
Our principal generation units are Beluga 3, 5, 6, 7 and 8. These
units, comprising 334 megawatt capacity, meet most of our load. All other units
are used principally as reserve. While the Beluga turbine-generators are fairly
old, they have been maintained in good working order with periodic upgrades.
Beluga 3 had a major overhaul in 1996. Beluga 5 received a major overhaul in
1997. Beluga 6 was "repowered" in 2000 adding in excess of 25 years to its life.
Beluga 7 is slated for repowering in 2001. Beluga 8, a steam turbine, was
overhauled in 1994 and is slated for another major overhaul in 2002.
25
The following matrix depicts nomenclature, run hours for 2000 and
percentages of contribution and other historical information for all Chugach
generation units.
Percent of
Commercial Operation Rating Run hours Percent of total time
Facility Date Nomenclature (MW)(1) (2000) generation available
-------- ---- ------------ ------- ------ ---------- ---------
Beluga Power
Plant (3)
1 1968 GE Frame 5 19.6 1872.2 3.83 93.6
2 1968 GE Frame 5 19.6 2051.3 4.19 98.2
3 1972 GE Frame 7 64.8 7255.2 14.84 90.9
5 1975 GE Frame 7 68.7 8204.5 16.78 95.1
6 1975 ABB 11D-4A 69.4 3719.3 7.61 42.3
7 1978 ABB 11D-4A 71.0 8270.2 16.91 94.2
8 1981 BB DK-21150(2) 55.0 8419.0 17.22 95.8
Bernice Lake
Power Plant
2 1971 GE Frame 5 19.0 0 0 N/A
3 1978 GE Frame 5 26.0 4.7 0.01 99.4
4 1981 GE Frame 5 22.5 5953.1 12.17 99.7
Cooper Lake
Hydroelectric
Plant
1 1960 BB MV 230/10 8.6 1394.6 2.85 21.6
2 1960 BB MV 230/10 8.6 1530.9 3.13 21.6
International
Generating
Station
1 1964 GE Frame 5 14.1 62.8 0.13 99.5
2 1965 GE Frame 5 14.1 99.2 0.20 99.9
3 1969 Westinghouse 191G 18.5 66.8 0.14 99.9
Eklutna
Hydroelectric
Plant (4)
1 1955 Newport News 5.8 N/A5 N/A5 N/A5
2 1955 Oerlikon custom 5.9 N/A5 N/A5 N/A5
System Total 511.2 48903.8 100.00
(1) Capacity rating in MW at 30 degrees Fahrenheit.
(2) Steam-turbine powered generator with heat provided by exhaust from
natural-gas fueled Units 6 and 7 (combined-cycle).
(3) Beluga Unit 4 and Bernice Lake Unit 1 were retired during 1994.
(4) The Eklutna Hydroelectric Plant is jointly owned by Chugach, MEA and
AML&P. The capacity shown is our 30% share of the plant's maximum
output.
(5) Because Eklutna Hydroelectric Plant is operated by MEA and managed by a
committee of the three owners, we do not record run hours or
in-commission rates.
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Transmission and Distribution Assets
As of December 31, 2000, our transmission and distribution assets
included 39 substations and 402 miles of transmission lines, 931 miles of
overhead distribution lines and 659 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. In the 1997 Eklutna
acquisition, we also acquired a partial interest in two substations and
additional transmission facilities.
Many substations and a substantial number of our transmission and
distribution rights-of-way are the subject of federal or state permits and
licenses. Under a federal license and a permit from the United States Forest
Service, we operate the Quartz Creek transmission substation, substations at
Hope, Summit Lake and Daves Creek, and transmission lines over all federal lands
between Cooper Lake on the Kenai Peninsula and Anchorage. Long-term permits from
the Alaska Division of Lands and the Alaska Railroad Corporation govern much of
the rest of our transmission system outside the Anchorage area. Within the
Anchorage area, we operate our University substation and several major
transmission lines pursuant to long-term rights-of-way grants from the U.S.
Department of the Interior, Bureau of Land Management, and transmission and
distribution lines have been constructed across privately owned lands pursuant
to easements across public rights-of-way and waterways pursuant to authority
granted by the appropriate governmental entity.
Title
Until the Release Date, substantially all of our tangible and some of
our intangible properties and assets, including generation, transmission and
distribution properties, but excluding all excepted property identified in the
Existing Indenture, are pledged to secure repayment of the 1991 Series A Bonds,
the bonds issued to CoBank, the 2001 Series A Bonds and all other bonds that may
be issued under the Existing Indenture. See "Description of the Bonds - Security
for Payment of the Obligations Prior to Release Date; Conversion to Unsecured
Obligations on Release Date."
In addition to the lien of the Existing Indenture, many of our
properties are burdened by easements, plat restrictions, mineral reservation,
water rights and similar title exceptions common to the area or customarily
reserved in conveyances from federal or state governmental entities, and to
additional minor tide encumbrances and defects. We do not believe that any of
these title defects will materially impair the use of our properties in the
operation of our business.
Under the Alaska Electric and Telephone Cooperative Act, we possess the
power of eminent domain for the purpose and in the manner provided by Alaska
condemnation laws for acquiring private property for public use.
Other Assets
Bradley Lake. We are a participant in the Bradley Lake hydroelectric
project, which is a 126 megawatt rated capacity hydroelectric facility near
Homer on the southern end of the Kenai Peninsula that was placed into service in
September 1991. The project is nominally scheduled at 90 megawatts to minimize
losses and insure system stability. We have a 27.4 megawatt or 30.4% share in
the Bradley Lake project's output, and take Seward's and MEA's shares which we
net bill to them, for a total of 45% of the project's capacity.
The project was financed and built by AEA through grants from the State
of Alaska and the issuance of $166 million principal amount of revenue bonds
supported by power sales agreements with six electric utilities that share the
output from the facility (Chugach, AML&P, Homer and MEA (through AEG&T), GVEA
and Seward). 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
27
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 commercialization (September, 1991) or when the revenue bond
principal is repaid, whichever is the longer. We believe that, under a
worst-case scenario, we could be faced with annual expenditures of approximately
$4.1 million as a result of our Bradley Lake take-or-pay obligations. We believe
that this expense would be recoverable through a fuel surcharge. The share of
Bradley Lake indebtedness for which we are responsible is approximately
$44,000,000. 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
another 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
AEG&T/Homer's share of the Bradley Lake project 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 Homer. 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 purchased a 17%
undivided interest in 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 2000, 96% of our power was generated from gas, and 85% of that
gas-fired generation took place at Beluga.
Our primary sources of natural gas are the Beluga River Field producers
(Phillips Alaska, Inc. ("Phillips"), AML&P and Chevron USA Inc. ("Chevron"), and
Marathon. Phillips, AML&P and Chevron each own one-third of the gas produced
from the Beluga River Field and in 2000 provided approximately equal shares of
the Beluga gas. We have approximately 378 billion cubic feet ("BCF") of
remaining gas committed to us from the Beluga River Field producers and
Marathon. We currently use approximately 23 BCF of natural gas per year for firm
service. We believe that this usage will increase approximately 0.5 BCF per year
and estimate that our contract gas will last 15 to 19 years. The deliverability
requirements under the Beluga and Marathon contracts are in excess of the peak
winter demand requirements of the Beluga plant.
Beluga River Field Producers
We have similar requirements contracts with each of Phillips, AML&P and
Chevron that were executed in April 1989, superseding contracts that had been in
place since 1973. Each of the contracts with the Beluga River Field producers
provides for delivery of gas on different terms in three different periods.
Period 1 related to the delivery of gas previously committed by the respective
producer under the 1973 contracts and ended in June 1996.
During Period 2, which began in June 1996 and continues until the
earlier of the delivery of 180 BCF of natural gas or December 31, 2013, we are
entitled to take delivery of up to 180 BCF of natural gas (60 BCF per Beluga
River Field producer). During this period, we are required to take 60% of our
28
total fuel requirements at Beluga from the three Beluga River Field producers,
exclusive of gas purchased at Beluga under the Marathon contract for use in
making sales to GVEA or certain other wholesale purchasers. The price for gas
during this period under the Phillips and AML&P contracts is approximately 88%
of the price of gas under the Marathon contract (described below) ($1.8617 per
thousand cubic feet ("MCF") on January 1, 2001), plus taxes. The price during
this period under the Chevron contract is approximately 110% of the price of gas
under the Marathon contract (described below) ($2.3271 per MCF on January 1,
2001), plus taxes.
During Period 3 under the Beluga River Field producers' contracts,
which begins on the earlier of December 31, 2013, or the end of Period 2, we may
become entitled to take delivery of up to 120 BCF of natural gas (40 BCF per
producer). Whether any gas will be taken in Period 3, and the price and take
requirements with respect thereto, are to be determined in the future based upon
then-current market conditions.
We have supplemental, annually renewable contracts with the Beluga
River Field producers to supply supplemental gas (for peak periods of energy
usage) if they have it available in excess of the amounts guaranteed in the
basic contracts. The supplemental gas contracts raise the daily deliverability
of gas from the Beluga River Field producers to an aggregate of 85,200 MCF per
day. The base price of the gas under these contracts is the same as the base
price under the Marathon contract (described below), plus taxes.
Marathon
We entered into a requirements contract with Marathon in September 1988
for an initial commitment of 215 BCF. The contract expires on the earlier of
December 31, 2015, or the date on which Marathon has delivered to us a volume of
gas in total which equals or exceeds 215 BCF, which we currently expect to occur
by mid-2009. The base price for gas under the Marathon contract is $1.35 per
MCF, adjusted quarterly to reflect the percentage change between the preceding
twelve-month period and a base period in the average prices of West Texas
Intermediate Crude Oil (a benchmark of the Light Sweet Crude Oil Futures Index),
the Producer Price Index for natural gas, and the Consumer Price Index for
heating fuel oil. The price on January 1, 2001, exclusive of taxes, was $2.1156
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 and 40% of the requirements at Beluga. Marathon also has a right of
first refusal to provide additional gas under any sales agreements that we may
enter into with electric utilities we do not currently serve.
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 Generating Station at a transportation rate of $0.63 per MCF.
In addition, ENSTAR agreed to transport gas on an interruptible basis for
off-system sales at a rate of $0.30 per MCF. The agreement contains a minimum
monthly bill of $2,600 for firm service.
We hold a reservation to receive our gas requirements at International
Generating Station from ENSTAR under a tariff approved by the RCA in the event
that the transportation agreement is subsequently canceled. Under the currently
suspended tariff, ENSTAR is obligated to supply all of the gas we require at a
price approved by the RCA. There would be a monthly minimum bill of $10,465 but
no requirement to actually use any gas at the International Generating Station.
The estimated delivered price if the tariff were reinstated is $3.00 per MCF.
29
Environmental Matters
Our operations are subject to certain federal, state and local
environmental laws, which we monitor to ensure compliance. The costs associated
with environmental compliance are included as a component of both the operating
and capital budget processes. We accrue for costs associated with environmental
remediation obligations when such costs are probable and reasonably estimable.
We discovered polychlorinated biphenyls ("PCBs") in paint, caulk and
grease at the Cooper Lake Hydroelectric Plant during initial phases of a turbine
overhaul. We are implementing a plan approved by the Environmental Protection
Agency to remediate the PCBs in the plant. We are also conducting an
investigation to determine whether any PCBs released from the plant are present
in Kenai Lake. We do not have an estimate at this time of the potential costs
involved in the investigation and we do not know whether any additional
remediation will be required.
Legal Proceedings
Matanuska Electric Association, Inc. v. Chugach Electric Association,
Inc.
On July 7, 1999, MEA filed a complaint against us in Alaska Superior
Court in Anchorage, asserting that we violated the Power Supply Agreement
between the parties, state statutes and our bylaws in failing to provide MEA
with information about several different matters that MEA asserts could affect
the cost of the power MEA purchases from us. MEA also asserted that we violated
the Power Supply Agreement in our management of our long-term bond indebtedness.
On February 8, 2000, MEA added a new claim in this proceeding. MEA
asked for an order directing that we be required to present our general rate
case filing to the Joint Rate Committee (an administrative body comprised of
representatives of Chugach and MEA) prior to presenting it to the RCA. We filed
our answer to MEA's Second Amended Complaint on March 10, 2000, opposing the
relief MEA requested.
Discovery in this matter is still in its preliminary stages. Trial is
set for February 2002. Because of the preliminary nature of the case, we are not
able to estimate the costs of our participation.
We have certain additional litigation matters and pending claims that
arise in the ordinary course of our business. In the opinion of management, no
individual matter or the matters in the aggregate is likely to have a material
adverse effect on our results of operations or financial condition.
30
MANAGEMENT
We operate under the direction of a Board of Directors that is elected
at large by our membership. Day-to-day business and affairs are administered by
the General Manager. Our seven-member Board of Directors sets policy and
provides direction to our General Manager. The following table sets forth
certain information with respect to our executive officers and directors.
Name Age Position
Eugene N. Bjornstad......................... 62 General Manager
Lee D. Thibert.............................. 45 Executive Manager, Transmission and
Distribution Network Services
Evan J. Griffith............................ 59 Executive Manager, Finance and Energy Supply
William R. Stewart.......................... 54 Executive Manager, Retail Services
Pat Jasper.................................. 72 President and Director
Elizabeth ("Pat") Kennedy................... 50 Vice President and Director
Bruce Davison............................... 53 Secretary and Director
Mary Minder................................. 61 Treasurer and Director
Christopher Birch........................... 62 Director
Jeffrey W. Lipscomb......................... 50 Director
H. A. ("Red") Boucher....................... 80 Director
Executive Officers
Eugene N. Bjornstad was appointed our General Manager on June 22, 1994. Prior to
that he served as Acting General Manager from March 28, 1994, until his
permanent appointment. He joined Chugach in 1983 and served as Executive
Manager, Operating Divisions from 1988 to 1994.
Lee D. Thibert, in a reorganization on June 1, 1997, was appointed our Executive
Manager, Transmission & Distribution Network Services. Prior to that he was
Executive Manager, Operating Divisions from June of 1994. Before moving up to
the Executive Manager position, he served as Director of Operations from May
1987.
Evan J. Griffith has been our Executive Manager, Finance and Energy Supply since
our internal reorganization on June 1, 1997. Prior to that, he was Executive
Manager, Finance & Planning from August 1989 to June 1997. Prior to coming to
us, he was Budget/Program Analyst for the Anchorage Municipal Assembly from
August 1984 to August 1989.
William R. Stewart has been our Executive Manager, Retail Services since the
June 1, 1997 reorganization. Prior to that, he was our Executive Manager,
Administration from July 1987 to June 1, 1997. He was our Division Director of
Administration from January 1984 to July 1987 and Staff Assistant to the General
Manager of Chugach from November 1982 to January 1984. He has been employed by
us since 1969.
Board of Directors
Pat Jasper has served as the President of the Board since April 2000. Ms. Jasper
was originally elected to the Board in April 1995. Since 1995, she has held
several offices including Secretary, Vice President and President. She is a
small business owner and has been a computer programmer and systems analyst.
31
Pat Kennedy serves as Vice President of the Board. Ms. Kennedy has served on the
board since 1993 and has served as both Secretary and President before holding
her current position. She is an attorney who has been licensed to practice law
since 1976 and has been in private practice since 1990.
Bruce Davison has 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 the Chugach Bylaws Committee. He is a
partner in the law firm of Davison & Davison, Inc.
Mary Minder has been the Treasurer since April 1997. Ms. Minder was elected to
the Board in April 1995 and since then has served as both Treasurer and
Secretary. She is a realtor and associate real estate broker.
Chris Birch was appointed to fill a Board vacancy in October 1996. Mr. Birch was
elected to that seat in April 1997 and since that time has served as a director.
He has previously served as Secretary and President. He is a professional
engineer for the Alaska Department of Transportation and Public Facilities.
Red Boucher was elected to the Board in April 1999. In addition to being a
director, Mr. Boucher owns a consulting firm, serves as president of a
telecommunication firm and hosts a weekly statewide TV show. He has held many
elected offices including Lieutenant Governor of Alaska.
Jeff Lipscomb is the newest member of the Board and was elected director in
April 2000. Mr. Lipscomb is the principal of JWL Engineering which he founded in
1995. He is a professional mechanical engineer with over 20 years of experience
in Alaskan oil and gas production facility design.
EXECUTIVE COMPENSATION
Cash Compensation
The following table sets forth all remuneration paid by us for the last
three years to each of our four executive officers, each of whose total cash and
cash equivalent compensation exceeded $100,000 for 2000, and for all such
executive officers as a group:
Name Principal Position Year Salary Bonus Total
Eugene N. Bjornstad General Manager 2000 $230,074 $ 0 (1) $230,074
1999 $168,057 $ 36,891 $204,948
1998 $166,427 $ 33,996 $200,423
Lee D. Thibert Executive Manager, 2000 $131,710 $ 0 (1) $131,710
Transmission & 1999 $123,390 $ 12,757 $136,147
Distribution
Network Services 1998 $125,880 $ 0 $125,880
Evan J. Griffith Executive Manager, 2000 $131,657 $ 0 (1) $131,657
Finance
& Energy Supply 1999 $135,140 $ 12,757 $147,897
1998 $131,634 $ 3,300 $134,934
William R. Stewart Executive Manager, 2000 $134,398 $ 0 (1) $134,398
Retail Services 1999 $137,376 $ 12,757 $150,133
1998 $140,193 $ 3,300 $143,493
1 Year 2000 bonuses have not been granted.
32
Our directors are compensated for their services in the amount of $100
per board meeting attended (including committee meetings) up to a maximum of
seventy meetings per year for a director and eighty-five meetings per year for
the President. Upon termination, Mr. Bjornstad's employment agreement provides
that he may receive an amount equal to his salary for the greater of six months
or remaining term of his employment agreement (which number shall not be less
than six months) plus any accrued annual leave or other compensation then due as
of the effective date of the notice of termination.
Compensation Pursuant to Plans
We have elected to participate in the National Rural Electric
Cooperative Association ("NRECA") Retirement and Security Program (the "Plan"),
a multiple employer defined benefit master pension plan maintained and
administered by the NRECA for the benefit of its members and their employees.
The Plan is intended to be a qualified pension plan under Section 401(a) of the
Code. All our employees not covered by a union agreement become participants in
the Plan on the first day of the month following completion of one year of
eligibility service. An employee is credited with one year of eligibility
service if he completes 1,000 hours of service either in his first twelve
consecutive months of employment or in any calendar year for Chugach 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
(as hereinafter defined) or, if earlier, by attaining age sixty-two. A
participant may elect to receive actuarially reduced early retirement pension
benefits before his normal retirement date provided he has attained age
fifty-five.
Pension benefits paid in normal form are paid monthly for the remaining
lifetime of the participant. Unless an actuarially equivalent optional form of
benefit payment to the participant is elected, upon the death of a participant
the participant's surviving spouse will receive pension benefits for life equal
to 50% of the participant's benefit. The annual amount of a participant's
pension benefit and the resulting monthly payments the participant receives
under the normal form of payment are based on the number of his years of
participation in the Plan (benefit service) and the highest five-year average of
the annual rate of his base salary during the last ten years of his
participation in the Plan (final average salary). Annual compensation in excess
of $200,000, as adjusted by the Internal Revenue Service for cost of living
increases, is disregarded after January 1, 1989. The participant's annual
pension benefit at his normal retirement date is equal to the product of his
years of benefit service (up to thirty) times final average salary times 2%. In
1998, NRECA notified us that there were employees whose pension benefits from
NRECA's Retirement & Security Program would be reduced because of limitations on
retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA
made available a Pension Restoration Severance Pay Plan and a Pension
Restoration Deferred Compensation Plan for cooperatives to adopt in order to
make employees whole for their lost benefits. In May 1998, we adopted both of
these plans to protect the benefits of current and future employees whose
pension benefits would be reduced because of these limitations.
33
The following table sets forth the estimated annual pension benefit
payable at normal retirement date for participants in the specified final
average salary and years of benefit service categories:
Final Average
Salary Years of Benefit Service
- ---------------- --------------------------------------------------------------
15 20 25 30+
-- -- -- ---
$125,000 $37,500 $50,000 $62,500 $75,000
$150,000 $45,000 $60,000 $75,000 $90,000
The annual pension benefits indicated above are the joint and surviving
spouse life annuity amounts payable by the Plan, and they are not subject to any
deduction for Social Security or other offset amounts.
Benefit service as of December 31, 2000 taken into account under the
Plan for the executive officers is shown below. Base salary for 2000 taken into
account under the Plan for purposes of determining final average salary is also
included.
Name Principal Position Benefit Service Covered Compensation
Eugene N. Bjornstad........... General Manager 16.7 $165,027
Lee D. Thibert................ Executive Manager, Transmission 12.7 $130,790
& Distribution Network Services
Evan J. Griffith.............. Executive Manager, Finance & 10.4 $130,166
Energy Supply
William R. Stewart............ Executive Manager, Retail 30.0 $130,187
Services
34
BOND INSURANCE
The following information has been furnished by MBIA Insurance
Corporation (the "Insurer") for use in this prospectus. Reference is made to
Appendix A to this prospectus for a specimen of the Insurer's policy.
The Insurer's policy unconditionally and irrevocably guarantees the
full and complete payment required to be made by or on behalf of Chugach to the
Paying Agent or its successor of an amount equal to (i) the principal of (either
at the stated maturity or by an advancement of maturity pursuant to a mandatory
sinking fund payment) and interest on, the 2001 Series A Bonds as such payments
shall become due but shall not be so paid (except that in the event of any
acceleration of the due date of such principal by reason of mandatory or
optional redemption or acceleration resulting from default or otherwise, other
than any advancement of maturity pursuant to a mandatory sinking fund payment,
the payments guaranteed by the Insurer's policy shall be made in such amounts
and at such times as such payments of principal would have been due had there
not been any such acceleration); and (ii) the reimbursement of any such payment
which is subsequently recovered from any owner of the 2001 Series A Bonds
pursuant to a final judgment by a court of competent jurisdiction that such
payment constitutes an avoidable preference to such owner within the meaning of
any applicable bankruptcy law (a "Preference").
The Insurer's policy does not insure against loss of any prepayment
premium which may at any time be payable with respect to any Bond. The Insurer's
policy does not, under any circumstance, insure against loss relating to: (i)
optional or mandatory redemptions (other than mandatory sinking fund
redemptions); (ii) any payments to be made on an accelerated basis; (iii)
payments of the purchase price of 2001 Series A Bonds upon tender by an owner
thereof; or (iv) any Preference relating to (i) through (iii) above. The
Insurer's policy also does not insure against nonpayment of principal of or
interest on the 2001 Series A Bonds resulting from the insolvency, negligence or
any other act or omission of the Paying Agent or any other paying agent for the
2001 Series A Bonds.
Upon receipt of telephonic or telegraphic notice, such notice
subsequently confirmed in writing by registered or certified mail, or upon
receipt of written notice by registered or certified mail, by the Insurer from
the Paying Agent or any owner of a Bond the payment of an insured amount for
which is then due, that such required payment has not been made, the Insurer on
the due date of such payment or within one business day after receipt of notice
of such nonpayment, whichever is later, will make a deposit of funds, in an
account with State Street Bank and Trust Company, N.A., in New York, New York,
or its successor, sufficient for the payment of any such insured amounts which
are then due. Upon presentment and surrender of such 2001 Series A Bonds or
presentment of such other proof of ownership of the 2001 Series A Bonds,
together with any appropriate instruments of assignment to evidence the
assignment of the insured amounts due on the 2001 Series A Bonds as are paid by
the Insurer, and appropriate instruments to effect the appointment of the
Insurer as agent for such owners of the 2001 Series A Bonds in any legal
proceeding related to payment of insured amounts on the 2001 Series A Bonds,
such instruments being in a form satisfactory to State Street Bank and Trust
Company, N.A., State Street Bank and Trust Company, N.A. shall disburse to such
owners or the Paying Agent payment of the insured amounts due on such 2001
Series A Bonds, less any amount held by the Paying Agent for the payment of such
insured amounts and legally available therefor.
The Insurer is the principal operating subsidiary of MBIA Inc., a New
York Stock Exchange listed company (the "Company"). The Company is not obligated
to pay the debts of or claims against the Insurer. The Insurer is domiciled in
the State of New York and licensed to do business in and subject to regulation
under the laws of all 50 states, the District of Columbia, the Commonwealth of
Puerto Rico, the Commonwealth of the Northern Mariana Islands, the Virgin
Islands of the United States and the Territory of Guam. The Insurer has two
European branches, one in the Republic of France and the other in the Kingdom of
35
Spain. New York has laws prescribing minimum capital requirements, limiting
classes and concentrations of investments and requiring the approval of policy
rates and forms. State laws also regulate the amount of both the aggregate and
individual risks that may be insured, the payment of dividends by the Insurer,
changes in control and transactions among affiliates. Additionally, the Insurer
is required to maintain contingency reserves on its liabilities in certain
amounts and for certain periods of time.
As of December 31, 1999, the Insurer had admitted assets of $7.0
billion (audited), total liabilities of $4.6 billion (audited), and total
capital and surplus of $2.4 billion (audited) determined in accordance with
statutory accounting practices prescribed or permitted by insurance regulatory
authorities. As of September 30, 2000, the Insurer had admitted assets of $7.5
billion (unaudited), total liabilities of $5.1 billion (unaudited), and total
capital and surplus of $2.4 billion (unaudited) determined in accordance with
statutory accounting practices prescribed or permitted by insurance regulatory
authorities.
Copies of the Insurer's year-end financial statements prepared in
accordance with statutory accounting practices are available without charge from
the Insurer. A copy of the Annual Report on Form 10-K of the Company is
available from the Insurer or the Securities and Exchange Commission. The
address of the Insurer is 113 King Street, Armonk, New York l0504. The telephone
number of the Insurer is (914) 273-4545.
Moody's Investors Service, Inc. rates the financial s.trength of the
Insurer "Aaa."
Standard & Poor's Ratings Services Group, a division of The McGraw-Hill
Companies, Inc., rates the financial strength of the Insurer "AAA."
Fitch IBCA, Inc. rates the financial strength of the Insurer "AAA."
Each rating of the Insurer should be evaluated independently. The
ratings reflect the respective rating agency's current assessment of the
creditworthiness of the Insurer and its ability to pay claims on its policies of
insurance. Any further explanation as to the significance of the above ratings
may be obtained only from the applicable rating agency.
The above ratings are not recommendations to buy, sell or hold the 2001
Series A Bonds, and such ratings may be subject to revision or withdrawal at any
time by the rating agencies. Any downward revision or withdrawal of any of the
above ratings may have an adverse effect on the market price of the 2001 Series
A Bonds. The Insurer does not guaranty the market price of the 2001 Series A
Bonds nor does it guaranty that the ratings on the 2001 Series A Bonds will not
be revised or withdrawn.
36
DESCRIPTION OF THE BONDS
The 2001 Series A Bonds will be issued under and secured initially by
the Existing Indenture. U.S. Bank Trust National Association currently acts as
trustee under the Existing Indenture (the "Trustee"). On the earliest date when
all bonds issued under the Existing Indenture before the issue date of the 2001
Series A Bonds cease to be outstanding or their holders have consented to
conversion to unsecured status (the "Release Date"), the Existing Indenture will
be superseded in its entirety by the Amended Indenture. Our currently
outstanding 1991 Series A Bonds Due 2002 are not redeemable, and our 1991 Series
A Bonds Due 2022 are not redeemable until March 15, 2002, so the earliest date
on which we expect that the Amended Indenture could take effect is March 15,
2002. For purposes hereof, reference to the "Indenture" refers to the Existing
Indenture at all times prior to the Release Date, and to the Amended Indenture
at all times on and after the Release Date. Obligations of all series which have
been or may be issued under the Indenture, including the 2001 Series A Bonds,
may be referred to herein as "Obligations."
The following summaries of certain provisions of the Indenture do not
purport to be complete and are subject to, and are qualified in their entirety
by reference to, all the provisions of the Indenture, including the definitions
therein of certain terms. Wherever particular sections of the Indenture or
capitalized terms are referred to, such sections and the definitions of such
capitalized terms contained in the Indenture are incorporated herein by
reference. The Indenture is included as an exhibit to the registration statement
of which this prospectus is a part. A copy of the Indenture may also be obtained
from the Trustee or from us.
General
The 2001 Series A Bonds will be issued in an aggregate principal amount
of $150 million. Until the Release Date, the 2001 Series A Bonds will be secured
by substantially all of our tangible and some of our intangible property. On the
Release Date, the 2001 Series A Bonds will become unsecured general obligations,
ranking equally and ratably with all of our other unsecured and unsubordinated
obligations. The 2001 Series A Bonds are not redeemable at any time prior to
their maturity.
The 2001 Series A Bonds will bear interest at the annual rate of 6.55%
(on the basis of a 360-day year) from their date of issuance or from the most
recent Interest Payment Date to which interest has been paid or provided for,
payable semi-annually on March 15 and September 15 of each year, commencing
September 15, 2001, to the Person in whose name the 2001 Series A Bonds are
registered at the close of business on the Regular Record Date for such
interest, which shall be the last day (whether or not a business day) of the
calendar month next preceding such Interest Payment Date. If interest on the
2001 Series A Bonds is not punctually paid or duly provided for, we will pay
such amount instead to each registered holder of the bonds on a special record
date not more than 15 nor less than 10 days prior to the date of the proposed
payment. Principal of, and premium (if any) and interest on, the 2001 Series A
Bonds will be payable, and the transfer of interests in the bonds will be
effected, through the facilities of The Depository Trust Company, a New York
corporation ("DTC"), as described under "Book-Entry System; Exchangeability."
The 2001 Series A Bonds will be issued in multiples of $1,000 denominations.
Security for Payment of the Obligations Prior to Release Date; Conversion to
Unsecured Obligations on Release Date
Until the Release Date, the 2001 Series A Bonds will be secured equally
and ratably with all other Obligations issued (whether previously or subsequent
to issuance of the 2001 Series A Bonds) under the Existing Indenture, by a first
lien on substantially all of our tangible properties and certain of our other
assets, including generation, transmission and distribution properties,
excluding Excepted Property. The Existing Indenture defines Excepted Property to
37
include, among other things, cash on hand, instruments and certain securities,
patents and trademarks, transportation equipment (including vehicles, vessels
and barges) in which a security interest cannot be perfected by filing a
financing statement under the Uniform Commercial Code, leases for an original
term of less than five years, certain nonassignable permits, licenses and
contractual rights, property located outside the State of Alaska and not used in
connection with our generation, transmission and distribution system, and other
personal property in which a security interest cannot legally be perfected. The
lien of the Existing Indenture is subject to certain permitted encumbrances (the
"Permitted Encumbrances"), which the Indenture defines to include, among other
things, certain identified restrictions, exceptions, reservations, conditions
and limitations existing on September 15, 1991, reservations in U.S. patents,
non-delinquent or contested tax liens, local improvement district assessments,
contractors' liens and similar liens arising in the ordinary course of business,
certain easements, leases and reservations and liens for non-delinquent rent or
wages. The lien of the Existing Indenture is also subject to a lien in favor of
the Trustee to recover amounts owing to the Trustee under the Indenture. In
addition, our title to the mortgaged property and the lien of the Existing
Indenture are subject to certain other prior rights and encumbrances which we do
not believe adversely affects in any material respect our right to use such
property to secure the 2001 Series A Bonds.
Immediately following this offering and the application of the proceeds
hereof to the repayment of $72,500,000 in principal amount of Obligations, there
will be approximately $396,000,000 of Obligations, including the 2001 Series A
Bonds, outstanding under the Existing Indenture.
From and after the Release Date, the 2001 Series A Bonds, all other
Obligations then still outstanding and any other Obligations thereafter issued
under the Indenture will be unsecured general obligations and will rank equally
with all of our other unsecured and unsubordinated obligations. On the Release
Date, any lien or security interest arising under the Indenture will
automatically terminate and the Trustee is required to take any actions we deem
reasonably necessary to confirm or give notice of the termination and release of
any lien or security interest arising under the Indenture and to evidence the
reconveyance, re-assignment and transfer to us of all right, title and interest
of the Trustee in the collateral.
Rights of Insurer
The Indenture provides that if any person provides an insurance policy,
letter of credit, surety bond or other undertaking that unconditionally
obligates that person to pay any Obligations when they become due, to the extent
not paid by us, then as long as that credit enhancer is not in default in
performing that undertaking, that credit enhancer (and not the holders of the
Obligations to which the credit enhancement relates) will be considered the
holder of those Obligations for purposes of giving any approval or consent to
any supplemental indenture or other amendment to the Indenture (other than
modifications that cannot be effecting without unanimous approval of the holders
of those Obligations), the giving any other approval, consent or notice,
effecting any waiver or authorization, exercising any remedies or the taking of
any other action under the Indenture. Because MBIA Insurance Corporation will
issue an insurance policy insuring the payment of principal and interest on the
2001 Series A Bonds, MBIA will have the exclusive authority to exercise such
powers and take such actions under the Indenture in lieu of the actual holders
of the 2001 Series A Bonds. See "Bond Insurance."
Release and Substitution of Property Prior to Release Date; Negative Pledge
After Release Date
Until the Release Date, property subject to the lien of the Existing
Indenture may be released to facilitate the day-to-day operation of our
business. In addition, property may be released upon deposit of cash, retirement
of Obligations or acquisition of additional property.
The lien of the Indenture terminates on the Release Date when the
Existing Indenture is replaced by the Amended Indenture. However, the Amended
Indenture will thereafter prohibit us from creating or permitting to exist any
38
mortgage, lien, pledge, charge, security interest or other encumbrance of any
kind (other than those arising by operation of law) for the purpose of securing
repayment of borrowed money or any obligation to pay the deferred purchase price
for goods or services, except for security interests securing other debt not
exceeding $5,000,000.
Rate Covenant
Until the Release Date, subject to any necessary approval or
determination of any regulatory authority with jurisdiction over rates, rents,
charges, fees and other compensation (collectively, "Rates"), the Indenture
requires us to establish and collect Rates for the use or the sale of the
output, capacity or service of our electric generation, transmission and
distribution system which are reasonably expected to yield Margins for Interest
for the 12-month period commencing with the effective date of such Rates equal
to at least 1.20 times total interest expense during such 12-month period.
Promptly upon any material change in the circumstances which were contemplated
at the time such Rates were most recently reviewed, but not less frequently than
once every 12 months, we will review the Rates and, subject to any necessary
regulatory approval, promptly establish or revise the Rates as necessary to
obtain the required Margins for Interest and produce moneys sufficient to enable
us to comply with our other covenants under the Indenture. After the Release
Date, the Amended Indenture will require us to establish and collect Rates
reasonably expected to yield Margins for Interest for each fiscal year equal to
1.10 times total interest expense for the fiscal year (other than interest on
subordinated debt). We must also review Rates at least annually and promptly
revise them to comply with the Margins for Interest covenant subject to any
necessary regulatory approvals.
Depreciation Deposits Prior to Release Date
Until the Release Date, the Indenture requires us to deposit with the
Trustee, on or before July 1 of each year, cash (a "Depreciation Deposit") in an
amount equal to the excess (if any) obtained by subtracting the aggregate amount
of property acquired by us since July 1, 1991 that is subject to the lien of the
Indenture to the date of such Depreciation Deposit from our aggregate
depreciation expense incurred from January 1, 1992 through the end of the
calendar year immediately preceding the date of deposit. Depreciation Deposits
and other amounts deposited with the Trustee may be withdrawn on the basis of
Bondable Additions of property or retirement or defeasance of Bonds. To date, we
have not been required to make, and have not made, any Depreciation Deposits.
The Indenture will not require us to make any Depreciation Deposits
after the Release Date.
Limitations on Issuance of Short-Term Debt Prior to Release Date
Until the Release Date, the Indenture prohibits us or any of our
subsidiaries from incurring or permitting to be outstanding any indebtedness
(other than trade payables) with an original maturity of less than one year or
which is redeemable at the option of the holder within one year from the date of
original issuance, if, after giving effect thereto, the outstanding principal
amount of such indebtedness (other than trade payables) would exceed 15% of our
net utility plant determined on a consolidated basis as of the end of the
immediately preceding fiscal quarter. Fifteen percent of our net utility plant
as of December 31, 2000 was approximately $70.4 million. This specific
restriction on our ability to issue short-term debt will end on the Release
Date.
Limitation on Certain Cash Investments Prior to Release Date
Until the Release Date, the Indenture prohibits us from investing or
directing the Trustee to invest more than 25% of the aggregate of (i) cash on
hand, (ii) moneys received by the Trustee following a release of property,
proceeds from a taking or insurance, or disposition of a portion of the trust
estate or other money the Indenture does not require to be applied in any other
manner, and (iii) cash deposited with the Trustee as a basis for Additional
39
Obligations, other than in (a) obligations unconditionally guaranteed by the
United States of America or certificates or other evidences of interests in
those obligations, (b) securities issued by any agency or instrumentality of the
United States of America or any corporation created pursuant to any act of
Congress, (c) commercial paper rated in either of the two highest rating
categories by a national credit rating agency, (d) demand or time deposits,
certificates of deposit and bankers' acceptances issued or accepted by any bank
or trust company having capital surplus and undivided profits aggregating at
least $50,000,000, (e) any non-convertible debt securities rated in any of the
three highest rating categories by a national credit rating agency, (f)
repurchase agreements that are secured by a perfected security interest in
securities listed in clauses (a) or (b) above entered into with a government
bond dealer recognized as a primary dealer by the Federal Reserve Bank of New
York or any bank described in clause (d) above, or (g) any short-term
institutional investment fund or account which invests solely in any of the
foregoing obligations. These restrictions on our cash investments will end on
the Release Date.
Book-Entry System; Exchangeability
The 2001 Series A Bonds will be represented by one or more global bonds
that we will deposit with DTC or its agent. The 2001 Series A Bonds will be
registered in the name of DTC's nominee, Cede & Co. The deposit of the 2001
Series A Bonds with DTC and their registration in the name of Cede & Co. will
effect no change in beneficial ownership. Upon the issuance of each global bond,
DTC will credit the accounts of persons held with it with the respective
principal amounts of the 2001 Series A Bonds represented by such global bond
designated by the Underwriters with respect to the 2001 Series A Bonds.
The 2001 Series A Bonds will settle in DTC's Same-Day Funds Settlement
System and trade in that system in book-entry form until maturity. Therefore,
secondary market trading activity for the 2001 Series A Bonds will settle in
immediately available funds. We will pay principal and interest to DTC in
immediately available funds. There can be no assurance as to the effect, if any,
that settlement in immediately available funds will have on trading activity in
the 2001 Series A Bonds.
DTC has advised as follows: It is a limited-purpose trust company
organized under the New York Banking Law, a "banking organization" within the
meaning of the New York Banking Law, a member of the Federal Reserve System, a
"clearing corporation" within the meaning of the New York Uniform Commercial
Code, and a "clearing agency" registered pursuant to the provisions of Section
17A of the Securities Exchange Act of 1934, as amended. DTC was created to hold
securities for its participating organizations and to facilitate the clearance
and settlement of securities transactions between participants in such
securities through electronic book-entry changes in accounts of its
participants. Direct participants include securities brokers and dealers
(including the underwriters), banks and trust companies, clearing corporations
and certain other organizations. Access to DTC's system is also available to
indirect participants such as banks, brokers, dealers and trust companies that
clear through or maintain a custodial relationship with a direct participants
either directly or indirectly. Persons who are not participants may beneficially
own securities held by DTC only through participants.
Under the terms of the Indenture, we and the trustee will treat the
persons in whose names the 2001 Series A Bonds are registered as the owners of
the 2001 Series A Bonds for the purpose of receiving payment of principal and
interest on the 2001 Series A Bonds and for all other purposes. Except as set
forth below, owners of beneficial interests in a global bond representing 2001
Series A Bonds will not be entitled to have 2001 Series A Bonds represented by
such global bond registered in their names, will not receive or be entitled to
receive physical delivery of 2001 Series A Bonds in definitive form and will not
be considered the owners or holders thereof under the Indenture including,
without limitation, for purposes of consenting to any amendment thereof or
supplement thereto.
40
DTC has no knowledge of the actual owners of beneficial interests in
the global bonds representing the 2001 Series A Bonds. DTC's records reflect
only the identity of the direct participants to whose accounts the 2001 Series A
Bonds are credited, which may or may not be the beneficial owners. Ownership of
beneficial interests in global bonds representing the 2001 Series A Bonds will
be shown on, and the transfer of that ownership will be effected only through,
records maintained by DTC's participants or persons that hold through DTC's
participants. DTC's participants will remain responsible for keeping account of
their holdings on behalf of their customers. The laws of some jurisdictions
require that certain purchasers of securities take physical delivery of such
securities in definitive form. Such limits and such laws may impair the ability
to transfer beneficial interests in a global bond.
Payment of principal of (and premium, if any) and interest, if any, on
2001 Series A Bonds registered in the name of or held by DTC or its nominee will
be made to DTC or its nominee, as the case may be, as the registered owner or
the holder of the global bonds representing the 2001 Series A Bonds. We expect
that DTC or its nominee, upon receipt of any payment of principal of (and
premium, if any) or interest on global bonds, will credit participants' accounts
on the date such payment is payable in accordance with their respective
beneficial interests in the principal amount of such global bonds as shown on
the records of DTC or its nominee. We also expect that payments by participants
to owners of beneficial interests in such global bond held through such
participants will be governed by standing instructions and customary practices,
as is now the case with securities held for the accounts of customers in bearer
form or registered in "street name", and will be the responsibility of such
participants. None of Chugach, the Trustee, any Paying Agent or the Security
Registrar for the 2001 Series A Bonds will have any responsibility or liability
for any aspect of the records relating to or payments made on account of
beneficial ownership interests in a global bond for the 2001 Series A Bonds or
for maintaining, supervising or reviewing any records relating to such
beneficial ownership interests.
Unless and until it is exchanged in whole for 2001 Series A Bonds in
definitive form, a global bond representing 2001 Series A Bonds may not be
transferred except as a whole by DTC to DTC's nominee by a nominee of DTC to DTC
or another nominee of DTC or by DTC or any such nominee to a successor of DTC or
a nominee of such successor.
We have obtained the information in this Section concerning DTC and
DTC's book-entry system from sources that we believe to be reliable. We take no
responsibility for the accuracy of such information.
If DTC is at any time unwilling or unable to continue as depositary for
the global bonds representing the 2001 Series A Bonds and a successor depositary
is not appointed by us within 90 days, we will issue 2001 Series A Bonds in
definitive registered form in exchange for the global bond or securities
representing the 2001 Series A Bonds. In addition, we may at any time and in our
sole discretion, determine not to have any 2001 Series A Bonds in registered
form represented by one or more global bonds and, in such event, will issue 2001
Series A Bonds in definitive registered form in exchange for the global bond or
securities representing the 2001 Series A Bonds. In any such instance, an owner
of a beneficial interest in a global bond will be entitled to physical delivery
in definitive form of 2001 Series A Bonds represented by such global bond equal
in principal amount to such beneficial interest and to have the 2001 Series A
Bonds registered in the name of the owner of such beneficial interest.
Additional Obligations
The aggregate principal amount of Obligations that may be issued under
the Indenture is not limited.
41
Issuance of Additional Bonds Prior to Release Date
Until the Release Date, additional bonds, ranking equally and ratably
with the 2001 Series A Bonds, may be issued from time-to-time in the aggregate
amount of (i) 10/11 (90.909%) of the amount of Bondable Additions, (ii) the
aggregate principal amount of retired or defeased Bonds, and (iii) deposits of
cash with the Trustee.
Taking into account the use of Bondable Additions in connection with
issuance of the 2001 Series A Bonds, the amount of Bondable Additions that will
remain available for issuance of additional Bonds prior to the Release Date is
$114,040,160, plus the bondable value of all Property Additions after December
31, 2000, minus the bondable value of all property subject to the lien of the
Indenture that is retired or disposed of after December 31, 2000
("Retirements"). For the purpose of calculating the amount of Property Additions
and Retirements, the bondable value of property is the lesser of its cost or
fair value to us. Until the Release Date, we cannot issue additional Bonds on
the basis of Bondable Additions or (where the new Bonds will accrue interest at
a rate greater than that accruing on the retired or deferred Bonds) retirement
or defeasance of Bonds unless we certify that (i) our Margins for Interest
(assignable margins plus interest expense, income tax accruals and non-recurring
charges) during a 12-month period within the 18-month period immediately
preceding its request for additional Bonds was at least 1.20 times total
interest expense during such 12-month period and (ii) the sum of our Margins for
Interest for such 12-month period plus the maximum annual interest (making
certain assumptions with respect to variable rate debt) that will accrue on the
additional Bonds to be issued (net of annual interest savings on any Bonds and
other obligations secured by liens prior to or equal in priority with the lien
of the Existing Indenture that are retired with the proceeds of such additional
Bonds) would equal at least 1.20 times the sum of the total interest expense
during such 12-month period plus such maximum annual interest that will accrue
on the additional Bonds to be issued (net of interest on retired Bonds and other
obligations secured by liens prior to or equal in priority to the lien of the
Existing Indenture).
If after the commencement of the period for which Margins for Interest
is being calculated, we acquire any property, or we will acquire with the
proceeds of the Bonds being issued any property which was, during the 6-month
period prior to its acquisition, used in a business similar to ours, then, in
computing Margins for Interest there shall be included, to the extent not
otherwise included, the net operating earnings or net operating losses of such
property for the entire 12-month period. The calculation of Margins for Interest
shall also be adjusted if an Independent Engineer of favorable national repute
determines that efficiencies, inefficiencies or other effects likely to result
from the acquisition are significant enough to render the historical performance
of the separate properties an inaccurate indicator of the future performance of
the combined properties. Such additional adjustment shall take into account the
efficiencies, inefficiencies or other effects to the extent determined by the
Independent Engineer.
Issuance of Additional Obligations After Release Date
Beginning on the Release Date, we may issue additional indebtedness
under the Amended Indenture, ranking equally and ratably with the 2001 Series A
Bonds, from time-to-time as authorized by the Board of Directors. Before issuing
any additional indebtedness on or after the Release Date, we must certify that
our Margins for Interest during a twelve (12) consecutive month period within
the 18-month period immediately preceding our request to the Trustee for
authentication of additional indebtedness under the Amended Indenture was at
least 1.10 times total interest expense during such 12-month period. The
additional indebtedness that we may issue may contain provisions for, among
other things, optional redemption, prepayment, amortization of principal, and
covenants and events of default that differ from the terms of the 2001 Series A
Bonds.
The aggregate principal amount of Additional Obligations which may be
authenticated and delivered and Outstanding under the Indenture is not otherwise
42
limited, except as provided in the provisions of any supplemental indenture
creating any series of Obligations and except as may be limited by law.
Limitation on Distributions to Members
The Indenture prohibits us from making any distribution, payment or
retirement of patronage capital (each a "Distribution") to our members prior to
the Release Date if, giving effect to such Distribution, (i) an Event of Default
then exists or (ii) the aggregate amount expended for Distributions after
September 15, 1991 would exceed the sum of $7 million plus 35% of our aggregate
assignable margins earned after December 31, 1990. At December 31, 2000, we were
permitted to distribute $4.14 million to our members. This restriction does not
apply if, giving effect to a Distribution, our aggregate equities and margins
would equal at least 45% of our total liabilities and equities as of the end of
the immediately preceding fiscal quarter.
Beginning on the Release Date, the Indenture will prohibit us from
making any Distribution if, giving effect to a Distribution, (i) an Event of
Default exists, or (ii) our aggregate equities and margins as of the end of our
most recent fiscal quarter would be less than thirty percent (30%) of our total
long-term debt and equities at such time. Notwithstanding these restrictions, we
would be permitted, in any fiscal year, to make a Distribution of up to the
lesser of (A) 5% of our aggregate equities and margins as of the end of the
immediately preceding fiscal year or (B) fifty percent (50%) of the prior fiscal
year's margins. For this purpose, aggregate equities and margins and total
long-term debt and equities shall not include any earnings retained in any of
our subsidiaries or affiliates or the debt of any subsidiary or affiliate.
Events of Default and Remedies
Events of Default under the Indenture are:
o failure to pay principal of or premium, if any, on any Obligation
when due (subject to any applicable grace period);
o failure to pay any interest on any Obligation when due, continued
beyond any applicable grace period (the duration of which, unless
specified otherwise is such Obligation, is 30 days);
o any other breach by us of any of our warranties or covenants
contained in the Indenture, continued for 30 days after written notice
as provided in the Indenture;
o failure to pay when due any portion of the principal of any of
indebtedness for money borrowed (other than pursuant to the Indenture),
which failure resulted in the indebtedness becoming due or being
declared due and payable prior to the date on which it would otherwise
have become due and payable, in an aggregate amount in excess of $1
million ($10 million after the Release Date) unless such indebtedness
is discharged or such acceleration rescinded within 10 days after such
acceleration (and, for nonpayment or acceleration prior to the Release
Date, continuance of such default for a period of 30 days after notice
thereof from the Trustee or the Holders of at least 10% in principal
amount of the Obligations); or
o certain other proceedings in bankruptcy, receivership, insolvency,
liquidation or reorganization.
In addition, it is an Event of Default after the Release Date if a judgment
against us in an amount exceeding $10,000,000 is not discharged or stayed within
the period ending on the later of (i) 30 days after the judgement date or
43
expiration of any such stay and (ii) 10 days after written notice of default
from the Trustee or holders of at least 10% of the principal amount of the
Outstanding Obligations.
Subject to the provisions of the Indenture relating to the duties of
the Trustee in case an Event of Default shall occur and be continuing, the
Trustee will be under no obligation to exercise any of its rights or powers
under the Indenture at the request or direction of any of the Holders, unless
such Holders shall have offered to the Trustee indemnity reasonably satisfactory
to the Trustee. Subject to such provisions for the indemnification of the
Trustee, the Holders of a majority in aggregate principal amount of the
Outstanding Obligations will have the right to require the Trustee to proceed to
enforce the Indenture and to direct the time, method and place of conducting any
proceeding for any remedy available to the Trustee or exercising any trust or
power conferred on the Trustee to the extent the discretion is not in conflict
with law and the Trustee has determined that the action is not unjustly
prejudicial to non-directing holders.
If an Event of Default shall occur and be continuing, either the
Trustee or the Holders of at least 25% in aggregate principal amount of the
Outstanding Obligations may accelerate the maturity of all Obligations. However,
after such acceleration, but before a judgment or decree based on acceleration,
the Holders of a majority in aggregate principal amount of Outstanding
Obligations may, under certain circumstances, rescind such acceleration if,
among other things, all Events of Default, other than the non-payment of
accelerated principal, have been cured or waived as provided in the Indenture.
No Holder of any Obligation will have any right to institute any
proceeding with respect to the Indenture or for any remedy thereunder, unless
(i) such Holder shall have previously given to the Trustee written notice of a
continuing Event of Default, (ii) the Holders of at least 25% in aggregate
principal amount of the Outstanding Obligations shall have made written request
and offered indemnity reasonably satisfactory to the Trustee to institute such
proceeding as trustee, (iii) the Trustee for 60 days after its receipt of such
notice, request and indemnity shall have failed to institute any such
proceeding, and (iv) the Trustee shall not have received from the Holders of a
majority in aggregate principal amount of the Outstanding Obligations a
direction inconsistent with such request during such 60-day period. However,
such limitations on the Holders' rights to institute proceedings do not apply to
a suit instituted by a Holder of an Obligation for the enforcement of payment of
the principal of and premium, if any, or interest on such Obligation on or after
the respective due date stated therein. If an Event of Default affects the
holders of the 2001 Series A Bonds only, any action previously described that
requires the approval of Holders of Obligations can be taken by the Holders of
the 2001 Series A Bonds alone in the same percentage.
The Indenture provides that the Trustee, within 90 days after the
occurrence of an Event of Default, shall give to the Holders of Obligations
notice of all uncured defaults known to it, except that in the case of a default
in the payment of principal of, premium (if any), sinking fund payment or
interest on any Obligations, the Trustee shall be protected in withholding such
notice if it in good faith determines that the withholding of such notice is in
the interest of the Holders of the Obligations.
The Indenture provides that in case an Event of Default shall occur and
be continuing, the Trustee shall exercise such of its rights and powers under
the Indenture, and use the same degree of care and skill in their exercise, as a
prudent person would exercise or use under the circumstances in the conduct of
his own affairs.
If an Event of Default occurs and is continuing prior to the Release
Date, the Trustee may sell the Trust Estate, in either judicial or nonjudicial
proceedings. The proceeds from disposition of the Trust Estate prior to the
Release Date, and any other moneys collected by the Trustee in the exercise of
any remedies available to it on behalf of the Holders, shall, after payment of
amounts owing to the Trustee, be applied as follows: (i) if all Obligations
shall have become due and payable, to the payment of Outstanding Obligations
without preference or priority between interest or principal or among
44
Obligations, (ii) if any principal shall not have become due and payable, then
(A) first to interest installments in the order of their maturity and (B) second
to principal or redemption price.
Following the Release Date, money collected by the Trustee following an
Event of Default shall be applied as follows: (i) to the payment of all amounts
due the Trustee; (ii) if all Obligations shall have become due and payable, to
the payment of Outstanding Obligations without preference or priority between
interest or principal (and premium, if any) or among Obligations; (iii) if any
principal shall not have become due and payable, then (A) first to interest
installments in the order of their maturity and (B) second to principal or
premium.
Prior to the date the Trustee obtains a judgment for the payment of
money due, the Holders of at a majority in principal amount of the Outstanding
Obligations, by written notice to the Trustee, may waive any past defaults,
except a default in payment of the principal or interest on any Obligation, or
in respect of any covenant or provision that by its terms cannot be modified or
amended without the consent of the Holder of each Obligation affected. Upon any
such waiver, the default shall cease to exist and any Event of Default arising
therefrom shall be deemed cured.
Because MBIA Insurance Corporation is a credit enhancer with respect to
the 2001 Series A Bonds, MBIA--and not the actual Holders of the 2001 Series A
Bonds--will have the right to exercise any remedies that would otherwise be
exercisable by the Holders of the 2001 Series A Bonds under the Indenture. See
"Rights of Insurer." The Indenture requires us to deliver to the Trustee, within
120 days after the end of each fiscal year, a written statement as to our
compliance (determined without regard to any grace period or notice requirement)
with all conditions and covenants under the Indenture. In addition, we required
to deliver to the Trustee, promptly after any of our officers may be reasonably
deemed to have knowledge of a default under the Indenture, a written notice
specifying the nature and duration of the default and the action we are taking
and propose to take with respect thereto.
Amendments and Supplemental Indentures
Without the Consent of Holders
Without the consent of the Holders of any Obligations, we and the
Trustee may from time-to-time enter into one or more supplemental indentures to
add to the conditions, limitations and restrictions on the authorized amount,
terms or purposes of the issue, authentication and delivery of Obligations or of
any series of Obligations under the Indenture; to create any new series of
Obligations; to evidence the succession of another corporation and the
assumption by any such successor of our covenants; to add to our covenants or to
surrender any of our rights or powers; to cure any ambiguity, to correct or
supplement any provision in the Indenture which may be inconsistent with any
other provision or to make any other provisions, with respect to matters or
questions arising under the Indenture, which shall not be inconsistent with the
provisions of the Indenture, provided such action shall not adversely affect the
interests of the Holders of the Obligations in any material respect; to modify,
eliminate or add to the provisions of the Indenture to the extent necessary to
effect the qualification of the Indenture under the Trust Indenture Act of 1939,
as amended (the "1939 Act"), or under any similar federal statute hereafter
enacted; or to make any other change in the Indenture that, in the reasonable
judgment of the Trustee, will not materially and adversely affect the rights of
Holders of Obligations. Prior to the Release Date, we and the Trustee may also
enter into one or more supplemental indentures, without the consent of Holders
of Obligations, to correct or amplify the description of any property at any
time subject to the lien of the Indenture, to confirm property subject or
required to be subjected to the lien of the Indenture, or to subject additional
property to the lien of the Indenture.
Effective from and after the Release Date, without the consent of the
Holders of any Obligations, we and the Trustee may also from time-to-time,
without the consent of Holders of Obligations, enter into one or more
supplemental indentures to evidence the appointment of any successor trustee or
45
separate trustee and to define the rights, powers, duties and obligations
conferred upon any such separate trustee or trustees or to add or change the
Indenture to such extent as necessary to permit or facilitate the issuance of
Obligations in bearer form, registrable or not registrable as to principal and
with or without interest coupons or in book-entry form.
With the Consent of the Holders
With the consent of the Holders of not less than a majority in
principal amount of the Obligations of all series then Outstanding affected by
such supplemental indenture, we and the Trustee may enter into one or more
supplemental indentures to add, change or eliminate any of the provisions of the
Indenture or modify the rights of the Holders of Obligations, but no such
supplemental indenture shall, without the consent of the Holder of each
Outstanding Obligation affected thereby, change the Stated Maturity of or reduce
the principal of, or any installment of interest on, any Obligation, or any
premium payable upon the redemption thereof, or change any Place of Payment
where any Obligation, or the interest thereon is payable, or impair the right to
institute suit for the enforcement of any such payment on or after the Stated
Maturity thereof (or, in the case of redemption, on or after the Redemption
Date); reduce the percentage in principal amount of the Outstanding Obligations
the consent of the Holders of which is required for various purposes; modify
what constitutes an Outstanding Obligation, modify the Indenture in such a
manner as to affect the rights of the Holders to the benefits of the sinking
fund; modify the Indenture as to the application of moneys received by the
Trustee; or permit (prior to the Release Date) the creation of any lien ranking
prior to or on a parity with the lien of the Indenture with respect to any of
the Trust Estate.
Defeasance
The Indenture provides that Obligations of any series will be deemed to
have been paid, and (subject to receipt of certain rulings or opinions relating
to tax matters) all obligations of the Company to be holders of such Obligations
will be discharged, if we deposit with the Trustee Defeasance Securities the
principal and interest on which when due, together with cash deposited by us
with the Trustee, will provide moneys sufficient to pay when due the principal
or (if applicable) Redemption Price and interest due and to become due on such
Obligations. Defeasance Securities are defined to include bonds or other
obligations the principal and interest on which constitute direct obligations
of, or are unconditionally guaranteed by, the U.S. Government, certain
AAA-rated, pre-refunded municipal bonds, and certificates of interest or
participation in any such obligations, or in specified portions thereof. If
sufficient Defeasance Securities are deposited with respect to Obligations of
any series at any time at which the Indenture imposes a lien on any of our
property or assets, any such lien of the Indenture shall be deemed to have been
extinguished with respect to the Obligations of such series.
Trustee, Paying Agent
The Trustee and Paying Agent under the Indenture is U.S. Bank Trust
National Association.
CERTAIN FEDERAL INCOME TAX MATTERS
Qualification as a Tax-Exempt Entity
We currently qualify for exemption from federal income tax under
Section 501(c)(12) of the Code. In order to maintain our qualification as a
tax-exempt entity as an organization described in Section 501(c)(12) of the
Code, we must operate on a cooperative basis and at least 85% of our income must
consist of amounts collected from members for the sole purpose of meeting losses
and expenses.
46
Unrelated Business Taxable Income
Entities like Chugach that are exempt from federal income tax under
Section 501(a) of the Code are nonetheless subject to tax on the amount of their
"unrelated business taxable income." Unrelated business taxable income is income
derived from an "unrelated trade or business" regularly carried on by a
tax-exempt entity. The Code defines an unrelated trade or business, in general,
as a trade or business the conduct of which is not substantially related to the
exercise or performance by the tax-exempt entity of the purpose or function
constituting the basis for its tax exemption.
UNDERWRITING
Subject to the terms and conditions in the Underwriting Agreement,
dated April 11, 2001 (the "Underwriting Agreement"), between Chugach and J.P.
Morgan Securities Inc. (the "Underwriter"), we have agreed to sell the entire
amount of the bonds to the Underwriter. The Underwriting Agreement provides that
the obligations of the Underwriter to pay for and accept delivery of the bonds
is subject to approval of certain legal matters by its counsel and to certain
other conditions. The Underwriter is committed to purchase all of the bonds if
any are purchased.
The Underwriter has advised us that it proposes to offer all or part of
the bonds directly to the public initially at the offering price set forth on
the cover page of this Prospectus and to dealers at such prices less a
concession not in excess of 0.65% of the principal amount thereof. After the
initial offering, the public offering price and concession may be changed.
We have agreed to indemnify the Underwriter against certain civil
liabilities, including liabilities under the Securities Act of 1933, or to
contribute to payments the Underwriter may be required to make in connection
with the sale of the bonds.
The 2001 Series A Bonds are a new issue of securities with no
established trading market. No assurance can be given as to the liquidity of, or
the existence of a trading market for, the bonds. The Underwriter has advised us
that it intends to make a market in the bonds but is not obligated to do so and
may discontinue making a market at any time without notice. In order to
facilitate the offering of the bonds, the Underwriter may engage in transactions
that stabilize, maintain or otherwise affect the price of the bonds.
Specifically, the Underwriter may overallot in connection with the offering,
creating a short position in the bonds for its own account. In addition, to
cover over allotments or to stabilize the price of the bonds, the Underwriter
may bid for, and purchase the bonds in the open market. Any of these activities
may stabilize or maintain the market price of the bonds above independent market
levels. The Underwriter is not required to engage in these activities and may
end any of the activities at any time.
The Underwriter may engage in transactions with and perform services
for us from time-to-time in the ordinary course of business.
LEGAL OPINIONS
Heller Ehrman White & McAuliffe LLP, Seattle, Washington, will pass
upon the legality of the 2001 Series A Bonds for us. Orrick, Herrington &
Sutcliffe LLP, New York, New York, will pass upon certain legal matters in
connection with the 2001 Series A Bonds for the underwriter.
47
EXPERTS
The financial statements and schedule of Chugach Electric Association,
Inc. as of December 31, 2000 and 1999, and for each of the years in the
three-year period ended December 31, 2000, have been included herein and in the
registration statement in reliance upon the report of KPMG LLP, independent
certified public accountants, appearing elsewhere herein, and upon the authority
of said firm as experts in accounting and auditing.
WHERE TO FIND ADDITIONAL INFORMATION ABOUT CHUGACH
We have filed with the Securities Exchange Commission ("SEC") a
registration statement on a Form S-1. This prospectus, which constitutes a part
of the registration statement does not contain all of the information included
in the registration statement. You may review a copy of the registration
statement, including exhibits, at the SEC's public reference rooms at (a)
Judiciary Plaza, 450 Fifth Street, N.W., Washington D.C. 20549, (b) Citicorp
Center, 500 West Madison Street, 14th Floor, Chicago, Illinois 60661-2511; and
(c) 7 World Trade Center, 13th Floor, New York, New York 10048. You can also
obtain copies of these documents, upon payment of a duplicating fee, by writing
to the Public Reference Section of the SEC at 450 Fifth Street, N.W., Washington
D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information about
the public reference rooms. Our SEC filings are also available to the public
from the SEC's web site at http://www.sec.gov.
The Existing and Amended Indentures require us to file reports under
the Securities Exchange Act of 1934, as amended. Quarterly and annual reports
will be made available upon request of holders of the 2001 Series A Bonds, which
annual reports will contain financial information that has been examined and
reported upon by, with an opinion expressed by, an independent public or
certified public accountant.
48
Financial Statements and Schedule Index
Financial Statements Page
Independent Auditors' Report F-2
Balance Sheets, December 31, 2000 and 1999 F-3 to F-4
Statements of Revenue, Expense and Patronage Capital,
Years ended December 31, 2000, 1999 and 1998 F-5
Statements of Cash Flows,
Years ended December 31, 2000, 1999 and 1998 F-6
Notes to Financial Statements F-7 to F-21
Financial Statement Schedule
Schedule - Valuation and Qualifying Accounts,
Years ended December 31, 2000, 1999 and 1998 F-22
F-1
Independent Auditors' Report
The Board of Directors
Chugach Electric Association, Inc.
We have audited the financial statements of Chugach Electric Association, Inc.
as listed in the accompanying index. In connection with our audits of the
financial statements, we have also audited the financial statement schedule as
listed in the accompanying index. 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 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
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, 2000 and 1999, and the results of its operations and its
cash flows for each of the years in the three-year period ended December 31,
2000, 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 23, 2001, except as to note 17,
which is as of March 6, 2001
F-2
CHUGACH ELECTRIC ASSOCIATION, INC.
Balance Sheets
December 31, 2000 and 1999
Assets 2000 1999
------ ---- ----
Utility plant (notes 2, 6, 13 and 14):
Electric plant in service $687,127,130 $ 641,627,328
Construction work in progress 42,027,617 47,257,296
---------- ----------
729,154,747 688,884,624
Less accumulated depreciation 259,999,872 243,082,832
----------- -----------
Net utility plant 469,154,875 445,801,792
----------- -----------
Other property and investments, at cost:
Nonutility property 443,555 413,515
Investments in associated organizations
(note 3) 9,857,153 8,946,861
--------- ---------
10,300,708 9,360,376
---------- ---------
Current assets:
Cash and cash equivalents, including
repurchase agreements of $3,905,283 in
2000 and $6,574,457 in 1999 1,695,162 4,110,030
Cash-restricted construction funds 378,848 538,404
Special deposits 212,163 182,164
Accounts receivable, less provision for
doubtful accounts of $441,933 in 2000
and $389,223 in 1999 19,200,912 17,730,994
Fuel cost recovery 2,915,733 180,755
Materials and supplies 15,357,198 17,180,136
Prepayments 755,276 861,947
Other current assets 332,246 341,702
-------------- --------------
Total current assets 40,847,538 41,126,132
------------ ------------
Deferred charges (notes 9 and 15) 19,442,859 22,067,237
------------ ------------
$ 539,745,980 $ 518,355,537
=========== =============
See accompanying notes to financial statements.
F-3
CHUGACH ELECTRIC ASSOCIATION, INC.
Balance Sheets, Continued
December 31, 2000 and 1999
Liabilities 2000 1999
----------- ---- ----
Equities and margins (note 11):
Memberships $1,009,663 $ 960,808
Patronage capital (note 4) 122,925,253 117,335,481
Other (note 5) 4,880,424 4,228,356
--------- ------------
128,815,340 122,524,645
----------- ------------
Long-term obligations, excluding current installments (notes 6, 7 and 11):
First mortgage bonds payable 169,542,000 194,139,000
National Bank for Cooperatives bonds
Payable 142,677,945 143,011,295
----------- -------------
312,219,945 337,150,295
----------- ------------
Current liabilities:
Current installments of long-term obligations
(notes 6, 7 and 11) 6,430,350 6,372,405
Short-term borrowings (note 6) 40,000,000 0
Accounts payable 9,493,875 9,508,851
Consumer deposits 1,324,213 1,059,677
Accrued interest 5,861,390 6,066,114
Salaries, wages and benefits 4,586,407 4,053,228
Fuel 8,154,559 4,381,304
Other 1,434,562 2,527,798
--------- ------------
Total current liabilities 77,285,356 33,969,377
---------- ------------
Deferred credits (note 12) 21,425,339 24,711,220
---------- ------------
$539,745,980 $518,355,537
============ ============
See accompanying notes to financial statements.
F-4
CHUGACH ELECTRIC ASSOCIATION, INC.
Statements of Revenues, Expenses and Patronage Capital
Years ended December 31, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Operating revenues $158,541,114 $ 142,644,327 $ 141,825,373
----------- ------------ ------------
Operating expenses:
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
----------- ------------ ------------
Interest:
On long-term debt 24,987,033 24,137,593 25,159,660
Charged to construction - credit (2,178,425) (1,000,246) (821,137)
On short-term debt 1,909,682 998,034 130,146
--------- ------------- -------------
Net interest 24,718,290 24,135,381 24,468,669
---------- ------------ ------------
Net operating margins 7,392,551 8,052,060 6,619,263
Nonoperating margins:
Interest income 703,807 592,208 711,155
Other 1,615,161 1,003,029 1,050,899
Property gain (loss) (31,741) 20,137 349,087
-------- ----------- ------------
Assignable margins 9,679,778 9,667,434 8,730,404
Patronage capital at beginning of year 117,335,481 109,622,996 104,800,092
Retirement of capital credits and
Estate payments (note 4) (4,090,006) (1,954,949) (3,907,500)
----------- ----------- ----------
Patronage capital at end of year $122,925,253 $117,335,481 $109,622,996
============ ============ ============
See accompanying notes to financial statements.
F-5
CHUGACH ELECTRIC ASSOCIATION, INC.
Statements of Cash Flows
Years ended December 31, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Cash flows from operating activities:
Assignable margins $ 9,679,778 $ 9,667,434 $ 8,730,404
Adjustments to reconcile assignable margins to net cash provided
by operating activities:
Depreciation and amortization 27,575,408 23,563,805 24,605,760
Capitalization of equity allowance (340,838) (151,474) (260,258)
Property (gains) losses and obsolete inventory write-off (25,425) 242 (349,087)
Other (1,155) (221) 60,734
Changes in assets and liabilities:
(Increase) decrease in assets:
Special deposits (29,999) (61,000) 30,540
Accounts receivable (1,469,918) (1,049,512) 2,549,024
Fuel cost recovery (2,734,978) 381,029 4,206,848
Prepayments 106,671 55,434 (359,010)
Materials and supplies, net 1,822,938 (1,216,702) (344,349)
Deferred charges (1,231,531) (14,179,418) (7,898,240)
Other assets 9,456 7,328 (43,615)
Increase (decrease) in liabilities:
Accounts payable (14,976) 670,093 1,800,524
Accrued interest (204,724) (656,211) (182,010)
Deferred credits (3,638,491) (2,973,944) (1,829,112)
Consumer deposits, net 264,536 66,061 (44,625)
Other liabilities 3,213,198 524,833 (3,129,329)
------------- --------------- --------------
Total adjustments 23,300,172 4,980,343 18,813,795
------------- --------------- -------------
Net cash provided by operating activities 32,979,950 14,647,777 27,544,199
------------- --------------- -------------
Cash flows from investing activities:
Extension and replacement of plant (46,736,359) (41,864,828) (20,269,038)
Increase in investments in associated organizations (909,137) (590,276) (552,827)
-------------- ---------------- --------------
Net cash (used) in investing activities (47,645,496) (42,455,104) (20,821,865)
-------------- ---------------- --------------
Cash flows from financing activities:
Transfer of restricted construction funds 159,556 (361,038) 187,412
Proceeds from short-term borrowings 40,000,000 0 0
Proceeds from long-term debt 0 72,500,000 0
Repayments of long-term debt (24,872,405) (40,983,801) (5,913,512)
Memberships and donations received 700,923 788,865 80,695
Retirement of patronage capital (4,090,006) (1,954,949) (3,907,500)
Net receipts (refunds) of consumer advances for construction 352,610 (384,294) (81,384)
------------- ---------------- --------------
Net cash provided by (used in) financing activities 12,250,678 29,604,783 (9,634,289)
------------- --------------- --------------
Net change in cash and cash equivalents (2,414,868) 1,797,456 (2,911,955)
Cash and cash equivalents at beginning of year $4,110,030 $ 2,312,574 $ 5,224,529
- ---------------------------------------------- ------------- --------------- -------------
Cash and cash equivalents at end of year $1,695,162 $ 4,110,030 $ 2,312,574
============= =========== =============
Supplemental disclosure of cash flow information - interest
expense paid, net of amounts capitalized 24,917,014 24,791,592 24,650,680
========== ========== ==========
See accompanying notes to financial statements.
F-6
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
December 31, 2000 and 1999
(1) Description of Business and Summary of Significant Accounting Policies
Description of Business
Chugach Electric Association, Inc. (Association or Chugach) is the
largest electric utility in Alaska. The Association is engaged in the
generation, transmission and distribution of electricity to directly
served retail customers in the Anchorage and upper Kenai Peninsula areas.
Through an interconnected regional electrical system, Chugach's power
flows throughout Alaska's Railbelt, a 400-mile-long area stretching from
the coastline of the southern Kenai Peninsula to the interior of the
state, including Alaska's largest cities, Anchorage and Fairbanks.
Chugach also supplies much of the power requirements of three wholesale
customers, Matanuska Electric Association (MEA), Homer Electric
Association (Homer) and the City of Seward (Seward).
The Association operates on a not-for-profit basis and, accordingly,
seeks only to generate revenues sufficient to pay operating and
maintenance costs, the cost of purchased power, capital expenditures,
depreciation, and principal and interest on all indebtedness and to
provide for reasonable margins and reserves. The Association is subject
to the regulatory authority of the Regulatory Commission of Alaska (RCA),
(formerly the Alaska Public Utilities Commission (APUC)).
Management Estimates
In preparing the financial statements, management of the Association is
required to make estimates and assumptions relating to the reporting of
assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the balance sheet and revenues and expenses
for the reporting period. Actual results could differ from those
estimates.
Regulation
The accounting records of the Association conform to the Uniform System
of Accounts as prescribed by the Federal Energy Regulatory Commission.
The Association meets the criteria, and accordingly, follows the
accounting and reporting requirements of Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types
of Regulation (SFAS 71). Revenues in excess of current period costs (net
operating margins and nonoperating margins) in any year are designated on
the Association's statement of revenues and expenses as assignable
margins. Retained assignable margins are designated on the Association's
balance sheet as patronage capital, which is assigned to each member on
the basis of patronage. This patronage capital constitutes the principal
equity of the Association.
Reclassifications
Certain reclassifications have been made to the 1998 and 1999 financial
statements to conform to the 2000 presentation.
F-7
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
Plant Additions and Retirements
Additions to electric plant in service are recorded at original cost of
contracted services, direct labor and materials, and indirect overhead
charges. 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.
Operating Revenues
Operating revenues are based on billing rates authorized by the RCA which
are applied to customers' usage of electricity. Included in operating
revenue are billings rendered to customers adjusted for differences in
meter read dates from year to year. The Association's tariffs include
provisions for the flow through of gas costs pursuant to existing gas
supply contracts.
Chugach entered into a settlement agreement with MEA and Homer in 1996.
The settlement agreement was designed to resolved a number of ratemaking
disputes and assure MEA and Homer that their base rates would be no
higher than those based on 1995 costs and would be reduced (and refunds
given) if our 1996, 1997 or 1998 test year costs to serve their needs
were significantly reduced. The RCA has required Chugach to make filings
of Chugach's cost of service to facilitate determination of any refunds
owed under the settlement agreement.
Calculations based on 1996 costs indicated that a rate reduction was
required and that a refund was owed for the previous periods. Chugach
recorded provisions for wholesale rate refunds that totaled $2,651,361 as
of December 31, 1999. Early in 2000, refunds of $86,132 were issued to
Homer and $1,809,801 to MEA that represented uncontested amounts owed
consistent with the 1996 test year filing.
In June 2000, the RCA issued its final order approving the 1996 test year
cost of service. As a result of this order, additional refunds were
issued to MEA and Homer in the amounts of $332,157 and $503,272,
respectively, on July 25, 2000. Consistent with the Settlement Agreement,
these refunds were based on demand and energy purchases retroactive to
January 1, 1997.
The process for RCA, MEA and Homer review of 1997 test year costs is
nearly complete. An order from the RCA was received February 27, 2001,
and no rate reduction or refunds were required. Both MEA and Chugach have
filed petitions for reconsideration of this order.
The 1998 test year cost calculation is currently being reviewed by the
RCA. Management believes that no rate reduction or refund will be
required based on the 1998 test year.
The RCA has required that Chugach file a general rate case based on the
2000 test year by June 30, 2001. This filing may request a modest
increase in base rates.
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 expires on September 1, 2001. The parties have
recently negotiated and executed an Amendment, extending the term of the
contract to January 31, 2006, subject to approval by the RCA.
In October 1998 Marathon Oil Company, one of Chugach's natural gas
suppliers, notified Chugach that it had reached a settlement with the
State of Alaska regarding additional excise and royalty taxes for the
period 1989 through 1998. In accordance with the purchase contract,
Chugach would be responsible for these additional taxes. The RCA approved
F-8
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
Chugach's plan to recover this over 12 months through the Fuel Surcharge
mechanism except for the retail portion in the amount of $436,778 that
was written-off at December 31, 1998. Recovery of this expense in rates
continued from April 1, 1999 through April 1, 2000. Despite RCA approval
and subsequent re-confirmation by the RCA, MEA has refused to pay the
portion of its monthly bill it considers to be recovery of the Marathon
tax. Effective December 20, 2000, by the Superior Court for the State of
Alaska, MEA was ordered to pay $298,004, representing the unpaid tax
liability and associated litigation costs. MEA has appealed this order to
the Alaska Supreme Court.
Investments in Associated Organizations
Investments in associated organizations represent capital requirements as
part of financing arrangements. These investments are non-marketable and
accounted for at cost.
Deferred Charges and Credits
Deferred charges, representing regulatory assets, are amortized to
operating expense over the period allowed for rate-making purposes,
generally five years.
Nonrefundable contributions in aid of construction are credited to the
associated cost of construction of property units. Refundable
contributions in aid of construction are held in deferred credits pending
their return or other disposition.
Depreciation and Amortization
Depreciation and amortization rates have been applied on a straight-line
basis and at December 31, 2000 are as follows:
Rate (%)
Steam production plant 2.70 - 2.96
Hydraulic production plant 1.33 - 2.88
Other production plant 3.34 - 6.50
Transmission plant 1.85 - 5.37
Distribution plant 2.10 - 4.55
General plant 2.22 - 20.00
Other 1.88 - 2.75
In 1997 an update of the Depreciation Study was completed utilizing
Electric Plant in Service balances as of December 31, 1995. Depreciation
rates developed in that study were implemented in January, 1998. In 2000
another update of the study was completed. Depreciation rates determined
in that study will be implemented upon approval by the RCA.
Capitalized Interest
Allowance for funds used during construction and interest charged to
construction - credit are the estimated costs during the period of
construction of equity and borrowed funds used for construction purposes.
The Association capitalized such funds at the average rate (adjusted
monthly) of 7.9% during 2000, 7.4% during 1999 and 8.3% during 1998.
F-9
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
Cash and Cash Equivalents
For purposes of the statement of cash flows, the Association considers
all highly liquid debt instruments with a maturity of three months or
less upon acquisition by the Association (excluding restricted cash and
investments) to be cash equivalents.
Materials and Supplies
Materials and supplies are stated at the lower of cost or market and
valued at average cost.
Fair Value of Financial Instruments
Statement of Financial Accounting Standards 107, Disclosures About the
Fair Value of Financial Instruments, requires disclosure of the fair
value of certain on and off balance sheet financial instruments for which
it is practicable to estimate that value. The following methods are used
to estimate the fair value of financial instruments:
Cash and cash equivalents and restricted cash - the carrying amount
approximates fair value because of the short maturity of those
instruments.
Investments in associated organizations - the carrying amount
approximates fair value because of limited marketability and the
nature of the investments.
Consumer deposits - the carrying amount approximates fair value
because of the short refunding term.
Long-term obligations - the fair value is estimated based on the
quoted market price for same or similar issues (note 7).
Forward rate lock agreements - the fair value is estimated based on
discounted cash flow using current rates.
Financial Instruments and Hedging
The Association uses U.S. Treasury forward rate lock agreements to hedge
expected interest on probable debt refinancings. Under the guidance of
SFAS No. 80, Accounting for Futures Contracts, the Association has
accounted for the treasury rate lock agreement as a hedge. Accordingly,
the unrealized gain or loss has not been recorded and will be treated as
a regulatory asset or liability upon settlement (note 6).
Income Taxes
The Association is exempt from federal income taxes under the provisions
of Section 501(c)(12) of the Internal Revenue Code, except for unrelated
business income. For the years ended December 31, 2000, 1999 and 1998
the Association received no unrelated business income.
Environmental Remediation Costs
The Association accrues for losses 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.
F-10
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
2) Utility Plant Summary
Major classes of electric plant as of December 31 are as follows:
2000 1999
---- ----
Electric plant in service:
Steam production plant $60,392,869 $60,392,869
Hydraulic production plant 8,798,695 8,798,695
Other production plant 106,017,802 104,925,446
Transmission plant 211,860,829 211,881,174
Distribution plant 170,378,081 162,365,836
General plant 45,835,618 47,704,821
Unclassified electric plant in service 77,054,390 38,834,298
Equipment under capital lease 56,323 56,323
Other 6,732,523 6,667,866
------------------ ------------------
Total electric plant in service 687,127,130 641,627,328
Construction work in progress 42,027,617 47,257,296
------------------ ------------------
Total electric plant in service and
construction work in progress $729,154,747 $688,884,624
================== ==================
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.
F11
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
(3) Investments in Associated Organizations
Investments in associated organizations include the following at December
31:
2000 1999
---- ----
National Rural Utilities Cooperative Finance
Corporation (NRUCFC) $ 6,095,980 $ 6,095,980
National Bank for Cooperatives (CoBank) 3,600,133 2,708,200
NRUCFC capital term certificates 33,733 32,300
Other 127,307 110,381
------- ---------
$9,857,153 $8,946,861
========== ================
The Farm Credit Administration, CoBank's federal regulators, requires
minimum capital adequacy standards for all Farm Credit System
institutions. CoBank's loan agreements require, as a condition of the
extension of credit, that an equity ownership position be established by
all borrowers. The Association's investment in NRUCFC similarly was
required by its financing arrangements with NRUCFC.
(4) Patronage Capital
The Association has an approved Equity Management Plan which establishes
in general, a ten-year (for wholesale customers) and twenty-year (for
retail customers) capital credit retirement of patronage capital, based
on the members' proportionate contribution to Association assignable
margins. On January 19, 2000, the Board of Directors passed a resolution
putting all members on a 15-year rotation. At December 31, 2000, out of
the total of $122,925,253 patronage capital, the Association had assigned
$89,432,752 of such patronage capital (net of capital credit
retirements). Approval of actual capital credit retirements is at the
discretion of the Association's Board of Directors.
In December 1998 the Board of Directors authorized the retirement of
$2,208,997 of retail capital credits representing the balance of 1984
retail distribution patronage. The Board also authorized the retirement
of $1,533,287 of wholesale patronage for 1988.
In November 1999 the Board of Directors authorized the retirement of
$1,766,000 of retail patronage for 1984.
In November 2000 the Board of Directors authorized the retirement of
$3,750,000 of retail patronage for 1984 and 1985.
F-12
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
Following is a five-year summary of anticipated capital credit
retirements:
Year ending Wholesale Retail Total
----------- --------- ------ -----
2001 $ - $3,500,000 $3,500,000
2002 - 3,500,000 3,500,000
2003 - 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
(5) Other Equities
A summary of other equities at December 31 follows:
2000 1999
---- ----
Nonoperating margins, prior to 1967 $ 23,625 $ 23,625
Donated capital 183,907 183,907
Unredeemed capital credit retirement 4,672,892 4,020,824
----------- ----------
$4,880,424 $4,228,356
========== ==========
F-13
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
(6) Debt
Long-term obligations at December 31 are as follows:
2000 1999
---- ----
First mortgage bonds of 8.08% maturing in 2002
and 9.14% maturing in 2022 with interest payable
semiannually March 15 and September 15:
$ 11,329,000 $ 17,396,000
8.08%
9.14% 164,310,000 182,810,000
CoBank 8.95% bond maturing in 2002,
with interest payable monthly and
principal due semi-annually 511,295 816,700
CoBank 7.76% bond maturing in 2005,
with interest payable monthly 10,000,000 10,000,000
CoBank 5.60% bonds maturing in 2022, with
interest payable monthly 45,000,000 45,000,000
CoBank 5.60% bonds maturing in 2002,
2007 and 2012 with interest payable
monthly 15,000,000 15,000,000
CoBank, variable interest, with a rate of 8.20% at
December 31, 2000, bonds maturing in 2002, with
interest payable monthly 42,500,000 42,500,000
CoBank, variable interest, with a rate of 8.20% at December
December 31, 2000, bonds maturing in 2002, with
interest payable monthly 30,000,000 30,000,000
----------- -----------
Total long-term obligations 318,650,295 343,522,700
Less current installments 6,430,350 6,372,405
------------- -------------
Long-term obligations, excluding current installments
$ 312,219,945 $ 337,150,295
============= ==============
Substantially all assets are pledged as collateral for the long-term
obligations.
F-14
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
Maturities of Long-term Obligations
Year ending Sinking Fund Requirements Principal maturities Total
December 31
First mortgage CoBank
Bonds Mortgage bonds
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
------------ ---------- -----------
$175,639,000 $143,011,295 $318,650,295
============= ============ =============
Lines of Credit
The Association had an annual line of credit of $35,000,000 in 2000 and
1999 available with CoBank. The CoBank line of credit expires August 1,
2001 but carries an annual automatic renewal clause. At December 31, 2000
there was $35 million outstanding on this line of credit which carried an
interest rate of 8.20%. At December 31, 1999 there was no outstanding
balance. In addition, the Association had an annual line of credit of
$50,000,000 available at December 31, 2000 and 1999 with NRUCFC. At
December 31, 2000 there was $5 million outstanding on this line of credit
which carried an interest rate of 8.55%. At December 31, 1999 there was
no outstanding balance. The NRUCFC line of credit expires October 14,
2002.
Refinancing
On September 19, 1991, Chugach issued $314,000,000 of First Mortgage
Bonds, 1991 Series A (Bonds), for purposes of repaying existing debt to
the Federal Financing Bank and the Rural Electrification Administration
(now Rural Utilities Services). Pursuant to Section 311 of the Rural
Electrification Act, Chugach was permitted to prepay the REA debt at a
discounted rate of approximately 9%, resulting in a discount of
approximately $45,000,000 (note 12).
The bonds maturing in 2002 (Series A 2002 Bonds) are subject to annual
sinking fund redemption at 100% of the principal amount thereof which
commenced March 15, 1993. The bonds maturing in 2022 (Series A 2022
Bonds) are subject to annual sinking fund redemption at 100% of the
principal amount thereof commencing March 15, 2003. The Series A 2002
Bonds are not subject to optional redemption. The Series A 2022 Bonds are
redeemable at the option of Chugach on any interest payment date at an
initial redemption price commencing in 2002 of 109.140 of the principal
amount thereof declining ratably to par on March 15, 2012. The Bonds are
secured by a first lien on substantially all of Chugach's assets. The
Indenture prohibits outstanding short-term indebtedness (other than trade
payables) in excess of 15% of Chugach's net utility plant and limits
certain cash investments to specific securities.
F-15
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
In April 1997, Chugach reacquired $5,000,000 of the Series A 2022 Bonds
at a premium of 109.7500. Total transaction cost, including accrued
interest and premium, was $5,510,350.
In February 1999, Chugach reacquired $11,000,000 of the Series A 2022
Bonds at a premium of 117.05. Total transaction cost, including accrued
interest and premium, was $13,322,344.
In February 1999, Chugach reacquired $14,000,000 of the Series A 2022
Bonds at a premium of 116.25. Total transaction cost, including accrued
interest and premium, was $16,868,592.
In February 1999, Chugach reacquired $9,895,000 of the Series A 2022
Bonds at a premium of 116.75. Total transaction cost, including accrued
interest and premium, was $11,974,467.
In March 2000, Chugach reacquired $8,500,000 of the Series A 2022 Bonds
at a premium of 104.00. Total transaction cost, including accrued
interest and premium, was $9,215,502.
In April 2000, Chugach reacquired $10,000,000 of the Series A 2022 Bonds
at a premium of 108.875. Total transaction costs, including accrued
interest and premium, was $10,953,511.
On March 17, 1999, Chugach entered into a 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 Bonds due 2022 on their
call date (March 15, 2002). As of December 31, 2000, the aggregate
principal amount of Series A Bonds due 2022 was $164,310,000. Under the
treasury rate-lock contract, Chugach 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, Chugach 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 its stated target yield. The
treasury rate lock agreement fair value on December 31, 2000 was
$(8,600,000) and on December 31, 1999 was $13,000,000.
Chugach will adopt SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended by SFAS No. 138, on January 1, 2001.
This new standard requires all derivative financial instruments to be
reflected on the balance sheet. As of January 1, 2001, Chugach will
establish 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 the treasury rate lock agreement. Management
believes it is probable the regulatory asset will be recovered through
rates.
(7) Fair Value of Long-Term Obligations
The estimated fair values (in thousands) of the long-term obligations
included in the financial statements at December 31 are as follows:
2000 1999
---- ----
Carrying Fair Carrying Fair
Value Value Value Value
Long-term obligations
(including current installments) $318,650 $335,155 $343,523 $354,534
Fair value estimates are dependent upon subjective assumptions and
involve significant uncertainties resulting in variability in estimates
with changes in assumptions.
F-16
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
(8) Employee Benefits
Employee benefits for substantially all employees are provided through
the Alaska Electrical Trust and Alaska Hotel, Restaurant and Camp
Employees Health and Welfare Trust Funds (union employees) and the
National Rural Electric Cooperative Association (NRECA) Retirement and
Security Program (nonunion employees). The Association makes annual
contributions to the plans equal to the amounts accrued for pension
expense. For the union plans, the Association pays a contractual hourly
amount per union employee which is based on total plan costs for all
employees of all employers participating in the plan. In these master,
multiple-employer plans, the accumulated benefits and plan assets are not
determined or allocated separately to the individual employer. Costs for
union plans were approximately $2,017,000 in 2000, $1,832,000 in 1999 and
$1,805,000 in 1998. In 2000, 1999 and 1998, the Association contributed
$1,057,000, $868,000 and $813,000, respectively, to the NRECA plan.
(9) Deferred Charges
Deferred charges consisted of the following at December 31:
2000 1999
---- ----
Debt issuance and reacquisition costs $ 5,399,282 $ 6,196,555
Refurbishment of transmission equipment 253,087 262,346
Computer software and conversion 10,672,135 12,186,272
Studies 1,724,936 1,880,734
Business venture studies 562,435 273,660
Fuel supply negotiations 346,894 369,609
Major overhaul of steam generating unit 222,198 427,305
Environmental matters and other 261,892 470,756
------- -------
$19,442,859 $22,067,237
=========== ===========
(10) Employee Representation
Approximately 72% of the Association's employees are represented by the
International Brotherhood of Electrical Workers (IBEW). The various IBEW
contracts expire on June 30, 2003.
(11) Return of Capital
Under provisions of its long-term debt agreements, the Association is not
directly or indirectly permitted to declare or pay any dividend or make
any payments, distributions or retirements of patronage capital to
members if an event of default exists with respect to its bonds (event of
default), if payment of such distribution would result in an event of
default, or if the aggregate amount expended for all distributions on and
after September 26, 1991 exceeds the sum of $7,000,000 plus 35% of the
aggregate assignable margins (whether or not such assignable margins have
since been allocated to members) of the Association earned after December
31, 1990 (or, in the case such aggregate shall be a deficit, minus 100%
of such deficit). The Association may declare and make distributions at
any time if, after giving effect thereto, the Association's aggregate
F-17
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
margins and equities as of the end of the most recent fiscal quarter
would be not less than 45% of the Association's total liabilities and
equities as of the date of the distribution. The Association does not
anticipate that this provision will limit the anticipated capital credit
retirements described in note 4.
(12) Deferred Credits
Deferred credits at December 31 consisted of the following:
2000 1999
---- ----
Regulatory liability - unamortized gain on reacquired
debt $18,066,673 $ 21,271,412
Refundable consumer advances for construction 1,771,302 2,123,913
Estimated initial installation costs for transformers
and meters 323,821 272,554
Post retirement benefit obligation 286,200 286,200
New business venture 20,254 46,185
Other 957,089 710,956
------- -------
$21,425,339 $24,711,220
=========== ===========
In conjunction with the refinancing described in note 6, the Association
had recognized a gain of approximately $45,000,000. The APUC required the
Association to flow through the gain to consumers in the form of reduced
rates over a period equal to the life of the bonds using the effective
interest method; consequently, the gain has been deferred for financial
reporting purposes as required by SFAS 71. Approximately $1,553,000 of
the deferred gain was amortized in 2000. Approximately $1,215,000 of the
deferred gain was amortized in 1999. Approximately $1,700,000 of the
deferred gain was amortized in 1998.
(13) Bradley Lake Hydroelectric Project
The Association is a participant in the Bradley Lake Hydroelectric
Project (Bradley Lake). Bradley Lake was built and financed by the Alaska
Energy Authority (AEA) through State of Alaska grants and $166,000,000 of
revenue bonds. The Association and other participating utilities have
entered into take-or-pay power sales agreements under which shares of the
project capacity have been purchased and the participants have agreed to
pay a like percentage of annual costs of the project (including
ownership, operation and maintenance costs, debt service costs and
amounts required to maintain established reserves). Under these
take-or-pay power sales agreements, the participants have agreed to pay
all project costs from the date of commercial operation even if no energy
is produced. The Association has a 30.4% share of the project's capacity.
The share of debt service exclusive of interest, for which the
Association has guaranteed is approximately $44,000,000. Under a worst
case scenario, the Association could be faced with annual expenditures of
approximately $4.1 million as a result of its Bradley Lake take-or-pay
obligations. Management believes that such expenditures, if any, would be
recoverable through the fuel surcharge ratemaking process. Upon the
default of a Bradley Lake participant, and subject to certain other
conditions, AEA, through Alaska Industrial Development and Export
Authority, is entitled to increase each participant's share of costs pro
rata, to the extent necessary to compensate for the failure of another
F-18
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
participant to pay its share, provided that no participant's percentage
share is increased by more than 25%.
On April 6, 1999, AEA issued $59,485,000 of Power Revenue Refunding
Bonds, Third Series, for the purpose of refunding $59,110,000 of the
First Series Bonds. The refunded First Series Bonds were called on July
1, 1999. The refunding resulted in aggregate debt service payments over
the next nineteen years in a total amount approximately $9,500,000 less
than the debt service payments which would be due on the refunded bonds.
There was an economic gain of approximately $5,900,000. Economic gain is
calculated as the net difference between the present value of the old
debt service requirements and the present value of the new debt service
requirements, discounted at the effective interest rate and adjusted for
additional cash paid.
On April 13, 1999, AEA issued $30,640,000 of Power Revenue Refunding
Bonds, Fifth Series, for the purpose of refunding $28,910,000 of the
First Series Bonds. The refunded First Series Bonds were called on July
1, 1999. The refunding resulted in aggregate debt service payments over
the next twenty-three years in a total amount approximately $4,400,000
less than the debt service payments which would be due on the refunded
bonds. There was an economic gain of approximately $2,900,000.
On April 4, 2000, AEA issued $47,710,000 of Power Revenue Refunding
Bonds, Fourth Series, for the purpose of refunding $46,235,000 of the
Second Series Bonds. The refunded Second Series Bonds were called on July
1, 2000. The refunding resulted in aggregate debt service payments over
the next twenty-two years in a total amount approximately $6,400,000 less
than the debt service payment which would be due on the refunded bonds.
There was an economic gain of approximately $3,500,000.
The following represents information with respect to Bradley Lake at June
30, 2000 (the most recent date for which information is available). The
Association's share of expenses were $3,696,829 in 2000, $3,902,737 in
1999 and $4,112,292 in 1998 and are included in purchased power in the
accompanying financial statements.
(In thousands) Total Proportionate Share
Plant in service $ 306,872 $ 93,289
Accumulated depreciation (60,567) (18,170)
Interest expense 9,938 2,981
Other electric plant in service represents the Association's share of a
Bradley Lake transmission line financed internally and the Association's
share of the Eklutna Hydroelectric Project, purchased in 1997 (note 14).
(14) Eklutna Hydroelectric Project
During October 1997, the ownership of the Eklutna Hydroelectric Project
formally transferred from the Alaska Power Administration to the
participating utilities. This group consists of the Association along
with Matanuska Electric Association (MEA) and Municipal Light and Power
(AML&P).
F-19
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
Other electric plant in service includes $1,956,954 representing the
Association's share of the Eklutna Hydroelectric Plant. This balance will
be amortized over the estimated life of the facility. During the
transition phase and after the transfer of ownership, Chugach, MEA and
AML&P have jointly operated the facility. Each participant contributes
their proportionate share for operations and maintenance costs. Under net
billing arrangements, Chugach then reimburses MEA for their share of the
costs.
(15) Commitments and Contingencies
Contingencies
The Association is a participant in various legal actions, rate disputes,
personnel matters and claims both for and against its interests.
Management believes that the outcome of any such matters will not
materially impact the Association's financial condition, results of
operations or liquidity.
Long-Term Fuel Supply Contracts
The Association has entered into long-term fuel supply contracts from
various producers at market terms. The current contracts will expire in
15 to 20 years.
Significant Customers
The Association is the principal supplier of power under long-term
wholesale power contracts with MEA and HEA. These contracts represented
$45.2 million or 28.5% of operating revenues in 2000, and will expire in
2014.
Cooper Lake Hydroelectric Plant
The Association discovered polychlorinated biphenyls ("PCBs") in paint,
caulk and grease at the Cooper Lake Hydroelectric plant during initial
phases of a turbine overhaul. The Association is implementing a plan
approved by the Environmental Protection Agency to remediate the PCBs in
the plant. The Association is also conducting an investigation to
determine whether any PCBs released from the plant are present in Kenai
Lake. The Association does not have an estimate at this time of the
potential costs involved in the investigation and the Association does
not know whether any additional remediation will be required. Management
believes costs of this endeavor will be recoverable through rates and
therefore will have no material impact on the financial condition or
results of operations.
Regulatory Cost Charge
In 1992 the State of Alaska Legislature passed legislation authorizing
the Department of Revenue to collect a regulatory cost charge from
utilities in order to fund the APUC. The tax is assessed on all retail
consumers and is based on kilowatt hour (kWh) consumption. The Regulatory
Cost Charge has decreased since its inception (November 1992) from an
initial rate of $.000626 per kWh to the current rate of $.000318,
effective October 1, 2000.
(16) Segment Reporting
The Association had divided its operations into two reportable
segments: Energy and Internet service. The energy segment derives its
revenues from sales of electricity to residential, commercial and
wholesale customers, while the Internet segment derives its revenues
from provision of residential and commercial internet services and
products. The reporting segments follow the same accounting policies
F-20
CHUGACH ELECTRIC ASSOCIATION, INC.
Notes to Financial Statements
used for the Association's financial statements and described in the
summary of significant accounting policies. Management evaluates a
segment's performance based upon profit or loss from operations.
Jointly used assets are allocated by percentage of reportable segment
usage and centrally incurred costs are allocated using factors
developed by the Association, which are patterned upon usage. The
Internet segment began operations during 1998, the results of which are
immaterial to the financial statements. The following is a tabulation
of business segment information for the years ended December 31:
Operating Revenues 2000 1999
------------------
Internet $1,170,448 $374,296
Energy 157,370,666 142,270,031
----------- -----------
Total operating revenues 158,541,114 142,644,327
=========== ===========
Assignable Margins
Internet (1,505,518) (1,293,388)
Energy 11,185,296 10,960,822
---------- ----------
Total assignable margins 9,679,778 9,667,434
========= =========
Assets
Internet 550,275 564,477
Energy 539,195,705 517,791,060
----------- -----------
Total assets 539,745,980 518,355,537
=========== ===========
Capital Expenditures
Internet 163,565 508,082
Energy 46,572,794 41,356,746
---------- ----------
Total capital expenditures 46,736,359 41,864,828
========== ==========
(17) Sale of Segment
On March 6, 2001, the Association entered into an agreement to sell
substantially all the assets and customers of the Internet business
segment to an unrelated third party. The transaction is expected to
result in a nominal gain.
(18) Quarterly Results of Operations (unaudited)
2000 Quarter Ended
Dec. 31 Sept. 30 June 30 March 31
------- -------- ------- --------
Operating Revenue $44,282,842 $37,201,515 $36,185,683 $40,871,074
Operating Expense 36,351,256 31,192,307 29,183,255 29,703,456
Net Interest 6,384,593 6,078,364 6,114,471 6,140,861
------------ ------------ ------------ ------------
Net Operating Margins 1,546,993 (69,156) 887,957 5,026,757
Non-Operating Margins 1,450,456 220,261 267,174 349,336
--------- ------- ------- -------
Assignable Margins $ 2,997,449 $ 151,105 $ 1,155,131 $ 5,376,093
============ ============= ============ ============
1999 Quarter Ended
Dec. 31 Sept. 30 June 30 March 31
------- -------- ------- --------
Operating Revenue $38,837,034 $32,075,076 $32,307,980 $39,424,237
Operating Expense 30,637,296 26,163,772 27,033,946 26,621,873
Net Interest 6,148,973 5,905,993 5,949,006 6,131,408
--------- --------- --------- ---------
Net Operating Margins 2,050,765 5,311 (674,972) 6,670,956
Non-Operating Margins 1,090,556 199,106 170,377 155,335
--------- ------- -------- -------
Assignable Margins $ 3,141,321 $ 204,417 $ (504,595) $ 6,826,291
============ ============= ============ ============
F-21
Schedule
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, 2000 $ (389,223) (373,666) 320,956 (441,933)
December 31, 1999 (447,908) (331,895) 390,580 (389,223)
December 31, 1998 (368,029) (407,825) 327,946 (447,908)
F-22
Appendix A
Specimen of Insurer's Policy
STATEMENT OF INSURANCE
MBIA Insurance Corporation (the "Insurer") has issued a policy
containing the following provisions, such policy being on file at [INSERT NAME
OF TRUSTEE OR PAYING AGENT, INCLUDING CITY, STATE].
The Insurer, in consideration of the payment of the premium and
subject to the terms of this policy, hereby unconditionally and irrevocably
guarantees to any owner, as hereinafter defined, of the following described
obligations, the full and complete payment required to be made by or on behalf
of the Issuer to [INSERT NAME OF TRUSTEE OR PAYING AGENT] or its successor (the
"Paying Agent") of an amount equal to (i) the principal of (either at the stated
maturity or by any advancement of maturity pursuant to a mandatory sinking fund
payment) and interest on, the Obligations (as that term is defined below) as
such payments shall become due but shall not be so paid (except that in the
event of any acceleration of the due date of such principal by reason of
mandatory or optional redemption or acceleration resulting from default or
otherwise, other than any advancement of maturity pursuant to a mandatory
sinking fund payment, the payments guaranteed hereby shall be made in such
amounts and at such times as such payments of principal would have been due had
there not been any such acceleration); and (ii) the reimbursement of any such
payment which is subsequently recovered from any owner pursuant to a final
judgment by a court of competent jurisdiction that such payment constitutes an
avoidable preference to such owner within the meaning of any applicable
bankruptcy law. The amounts referred to in clauses (i) and (ii) of the preceding
sentence shall be referred to herein collectively as the "Insured Amounts."
"Obligations" shall mean: [INSERT LEGAL TITLE OF BONDS, CENTERED AS FOLLOWS:]
[$ PAR AMOUNT]
[ISSUER]
[DESCRIPTION OF BONDS]
Upon receipt of telephonic or telegraphic notice, such notice
subsequently confirmed in writing by registered or certified mail, or upon
receipt of written notice by registered or certified mail, by the Insurer from
the Paying Agent or any owner of an Obligation the payment of an Insured Amount
for which is then due, that such required payment has not been made, the Insurer
on the due date of such payment or within one business day after receipt of
notice of such nonpayment, whichever is later, will make a deposit of funds, in
an account with State Street Bank and Trust Company, N.A., in New York, New
York, or its successor, sufficient for the payment of any such Insured Amounts
which are then due. Upon presentment and surrender of such Obligations or
presentment of such other proof of ownership of the Obligations, together with
any appropriate instruments of assignment to evidence the assignment of the
Insured Amounts due on the Obligations as are paid by the Insurer, and
appropriate instruments to effect the appointment of the Insurer as agent for
such owners of the Obligations in any legal proceeding related to payment of
Insured Amounts on the Obligations, such instruments being in a form
satisfactory to State Street Bank and Trust Company, N.A., State Street Bank and
Trust Company, N.A. shall disburse to such owners or the Paying Agent payment of
the Insured Amounts due on such Obligations, less any amount held by the Paying
Agent for the payment of such Insured Amounts and legally available therefor.
This policy does not insure against loss of any prepayment premium which may at
any time be payable with respect to any Obligation.
As used herein, the term "owner" shall mean the registered owner of
any Obligation as indicated in the books maintained by the Paying Agent, the
Issuer, or any designee of the Issuer for such purpose. The term owner shall not
include the Issuer or any party whose agreement with the Issuer constitutes the
underlying security for the Obligations.
Any service of process on the Insurer may be made to the Insurer at
its offices located at 113 King Street, Armonk, New York 10504 and such service
of process shall be valid and binding.
This policy is non-cancelable for any reason. The premium on this
policy is not refundable for any reason including the payment prior to maturity
of the Obligations.
MBIA INSURANCE CORPORATION
A-1
CHUGACH ELECTRIC
ASSOCIATION, INC.
$150,000,000
2001 Series A Bonds
CHUGACH
-----------------------------
PROSPECTUS April 11, 2001
-----------------------------
JPMorgan