-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, EpTt+d4rizY26jvgaQ2MhFIXmhaPdxmWZf6D1a3JmNJdDiRIZU4dEYRiWz+C8ObD N1H+Dz8g95QvWGl4bf2tgA== 0000907303-01-000014.txt : 20010416 0000907303-01-000014.hdr.sgml : 20010416 ACCESSION NUMBER: 0000907303-01-000014 CONFORMED SUBMISSION TYPE: 424B4 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 20010412 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CHUGACH ELECTRIC ASSOCIATION INC CENTRAL INDEX KEY: 0000878004 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 920014224 STATE OF INCORPORATION: AK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-57400 FILM NUMBER: 1601249 BUSINESS ADDRESS: STREET 1: 5601 MINNESOTA DR STREET 2: PO BOX 196300 CITY: ANCHORAGE STATE: AK ZIP: 99518 BUSINESS PHONE: 9075637494 424B4 1 0001.txt 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. ------------ 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
------------ 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. 26 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 -----END PRIVACY-ENHANCED MESSAGE-----