-----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, E0ww3b5AVNU/NLJAvaqVrriSasm/bTCoxMFoh1Qwh/neDxOQ5dKb3nQXO1NSOxBz Y9sDiBEWMmnuEUEGFjdINw== 0000912057-01-542833.txt : 20020412 0000912057-01-542833.hdr.sgml : 20020412 ACCESSION NUMBER: 0000912057-01-542833 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20011212 ITEM INFORMATION: Other events ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 20011212 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHWESTERN CORP CENTRAL INDEX KEY: 0000073088 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 460172280 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-10499 FILM NUMBER: 1811698 BUSINESS ADDRESS: STREET 1: 125 S DAKOTA AVENUE STREET 2: SUITE 1100 CITY: SIOUX STATE: SD ZIP: 57104 BUSINESS PHONE: 6059782908 MAIL ADDRESS: STREET 1: 125 S DAKOTA AVENUE STREET 2: SUITE 1100 CITY: SIOUX STATE: SD ZIP: 57104 FORMER COMPANY: FORMER CONFORMED NAME: NORTHWESTERN PUBLIC SERVICE CO DATE OF NAME CHANGE: 19920703 8-K 1 a2065702z8-k.txt 8-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES AND EXCHANGE ACT OF 1934 DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED) DECEMBER 11, 2001 ------------------------ NORTHWESTERN CORPORATION (Exact name of registrant as specified in charter) DELAWARE -------- (State or other jurisdiction of incorporation) 0-692 46-0172280 ----- ---------- (Commission File Number) (IRS Employer Identification Number) 125 SOUTH DAKOTA AVENUE, SIOUX FALLS, SD 57104 ---------------------------------------------- (Address of registrant's principal executive office) Registrant's telephone number, including area code: (605) 978-2908 -------------- NOT APPLICABLE --------------------------------------------------------------- (Former Name or Former Address, if Changed Since Last Report) ITEM 5. OTHER EVENTS As previously reported, on September 29, 2000, NorthWestern Corporation entered into a definitive agreement to acquire the utility business of The Montana Power Company ("MPC Utility"), which comprises substantially all of the assets of the Utility of The Montana Power Company (the "Utility"), for approximately $1.1 billion, including the assumption of approximately $488 million in existing Montana Power debt and preferred stock. NorthWestern is accounting for this acquisition as a purchase. NorthWestern has made considerable progress in moving towards the completion of the acquisition of MPC Utility. The transaction has received approval of the Federal Energy Regulatory Commission and Hart-Scott-Rodino clearance as well as supermajority approval by The Montana Power Company's shareholders. The transaction is not required to receive the approval of NorthWestern's shareholders. Consummation of the transaction, however, remains subject to the approval of the Montana Public Service Commission, or MPSC. On November 9, 2001, the MPSC adopted a procedural schedule agreeing to issue an order regarding the acquisition no later than January 31, 2002. There can be no assurance as to whether the MPSC will grant its approval, whether the terms of any approval will be acceptable to the parties, or when any approval will be received. In addition, customary closing requirements apply such as confirmation of representations and warranties, compliance with covenants and the satisfaction of contractual closing conditions. There can be no assurance that these conditions will be satisfied. NorthWestern has obtained a commitment for a $1.0 billion credit facility, with a term of 364 days following the closing date of the acquisition, to finance the transaction and refinance NorthWestern's existing credit facility. The $1.0 billion credit facility will consist of a revolving credit facility and an acquisition term loan. The commitment letter contains customary conditions, which must be satisfied. NorthWestern currently intends to issue a combination of long term debt and equity following the closing of the acquisition of MPC Utility to refinance the acquisition term loan and provide working capital. Contemporaneously with the filing of this Form 8-K, NorthWestern and NorthWestern Capital Financing II, a Delaware statutory business trust (the "Trust"), are filing a Rule 424(b) prospectus supplement under NorthWestern's previously filed Registration Statements File Nos. 333-58491 and 333-82707 with respect to the issue and sale by the Trust of $200 million aggregate amount of trust preferred securities. All of the proceeds of the trust preferred securities will be invested by the Trust in subordinated debentures of NorthWestern. There can be no assurance that the issue and sale of the $200 million trust preferred securities will be consummated or the terms or actual amount of trust preferred securities sold will be. By filing this Form 8-K NorthWestern is incorporating by reference into the prospectuses relating to Securities offered by NorthWestern under its effective Registration Statements Nos. 333-58491, 333-82707, 333-64113, 333-80817 and 333-80819, certain pro forma and historical financial information contained in the 424(b) prospectus being filed contemporaneously herewith with respect to the issuance sale of the trust preferred securities as well as the combined financial statements of the Utility, all of which are filed as exhibits hereto. This Form 8-K includes as an exhibit (i) Unaudited Combined Financial Statements of the as of and for the nine months ended September 30, 2001 and Audited Combined Financial Statements of the Utility as of December 31, 2000 and 1999 and for each of the years in the three-year period ended December 31, 2000, (ii) Unaudited Pro Forma Combined Financial Information of NorthWestern as of and for the nine months ended September 30, 2001 and for the year ended December 31, 2000 and (iii) Unaudited Pro Forma Combined Financial Data of the Utility as of and for the nine months ended September 30, 2001 and for the year ended December 30, 2000. SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS On one or more occasions, we may make statements regarding our assumptions, projections, expectations, intentions or beliefs about future events. Words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and we believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, but there can be no assurance that our projections will be achieved or accomplished. In addition to other factors and matters discussed elsewhere in our most recent quarterly and annual reports that we file with the SEC, some important factors that could cause actual results or outcomes for NorthWestern to differ materially from those discussed in forward-looking statements include: - the adverse impact of weather conditions; - unscheduled generation outages; - maintenance or repairs; - unanticipated changes to fossil fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; - developments in the federal and state regulatory environment and the terms associated with obtaining regulatory approvals; - the rate of growth and economic conditions in our service territories and those of our subsidiaries; - the speed and degree to which competition enters our businesses; - the timing and extent of changes in interest rates and fluctuations in energy-related commodity prices; - risks associated with acquisitions, transition and integration of acquired companies; - availability of minority interest basis for loss allocation purposes; - changes in customer usage patterns and preferences; - changing conditions in the economy, capital markets and other factors identified from time to time in our filings with the SEC; and - our ability to complete the acquisition of the MPC Utility. Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS (c) EXHIBITS EXHIBIT NUMBER TITLE - ------ ----- 99.1 Unaudited Combined Financial Statements of the Utility as of and for the nine months ended September 30, 2001 and Audited Combined Financial Statements of the Utility as of December 31, 2000 and 1999 and for each of the years in the three-year period ended December 31, 2000. 99.2 Unaudited Pro Forma Combined Financial Information of NorthWestern Corporation as of and for the nine months ended September 30, 2001 and for the year ended December 31, 2000. 99.3 Unaudited Pro Forma Combined Financial Data of the Utility as of and for the nine months ended September 30, 2001 and for the year ended December 30, 2000. SIGNATURES Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. NorthWestern Corp. (Registrant) BY: /s/ Kipp D. Orme ---------------------------- Kipp D. Orme Vice President--Finance and Chief Executive Officer December 12, 2001 EXHIBIT INDEX EXHIBIT NUMBER TITLE - ------ ----- 99.1 Unaudited Combined Financial Statements of the Utility as of and for the nine months ended September 30, 2001 and Audited Combined Financial Statements of the Utility as of December 31, 2000 and 1999 and for each of the years in the three-year period ended December 31, 2000. 99.2 Unaudited Pro Forma Combined Financial Information of NorthWestern Corporation as of and for the nine months ended September 30, 2001 and for the year ended December 31, 2000. 99.3 Unaudited Pro Forma Combined Financial Data of the Utility as of and for the nine months ended September 30, 2001 and for the year ended December 30, 2000. EX-99.1 3 a2065702zex-99_1.txt EXHIBIT 99.1 Exhibit 99.1 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of NorthWestern Corporation: In our opinion, the accompanying combined balance sheet and the related combined statements of income, of other equity and of cash flows present fairly, in all material respects, the financial position of The Utility of The Montana Power Company and related subsidiaries and business trusts, consisting of the utility operations of The Montana Power Company, Montana Power Capital I, Discovery Energy Solutions, Inc., Canadian-Montana Pipe Line Corporation, Montana Power Services Company, One Call Locators, LLC, Montana Power Natural Gas Funding Trust and Colstrip Community Services Company, (collectively referred to as the "Utility"), at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Utility's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. PricewaterhouseCoopers LLP Portland, Oregon December 10, 2001 1 THE UTILITY OF THE MONTANA POWER COMPANY COMBINED STATEMENT OF INCOME
UNAUDITED --------- NINE MONTHS YEAR ENDED DECEMBER 31, ENDED ----------------------------------- 9/30/2001 2000 1999 1998 ------------------------------------------------ (Thousands of Dollars) REVENUES ................................... $ 536,306 $ 676,053 $ 657,081 $ 637,763 EXPENSES: Operations and maintenance .............. 417,772 433,699 301,908 289,008 Selling, general, and administrative .... 69,564 118,518 85,356 71,311 Taxes other than income taxes ........... 40,997 55,616 67,898 63,195 Depreciation and amortization ........... 42,765 54,123 69,694 71,580 ------------------------------------------------ 571,098 661,956 524,856 495,094 ------------------------------------------------ INCOME (LOSS) FROM OPERATIONS .............. (34,792) 14,097 132,225 142,669 INTEREST EXPENSE AND OTHER INCOME: Interest ................................ 24,721 35,880 47,363 55,510 Distributions on company obligated mandatorily redeemable preferred securities of subsidiary trust ....... 4,119 5,492 5,492 5,492 Other income - net ...................... (1,707) (14,481) (2,567) (2,570) ------------------------------------------------ 27,133 26,891 50,288 58,432 ------------------------------------------------ INCOME (LOSS) BEFORE INCOME TAXES ....... (61,925) (12,794) 81,937 84,237 INCOME TAX EXPENSE (BENEFIT) ............... (20,015) (19,599) 13,895 27,427 ------------------------------------------------ NET INCOME (LOSS) .......................... (41,910) 6,805 68,042 56,810 DIVIDENDS ON PREFERRED STOCK ............... 2,847 3,690 3,690 3,690 ================================================ NET INCOME (LOSS) AVAILABLE FOR LLC UNITS .. $ (44,757) $ 3,115 $ 64,352 $ 53,120 ================================================ LLC UNITS OUTSTANDING ...................... 10 10 10 10 BASIC AND DILUTED EARNINGS (LOSS) PER LLC UNIT ................................. $ (4,476) $ 312 $ 6,435 $ 5,312 ================================================
The accompanying notes are an integral part of these financial statements. 2 THE UTILITY OF THE MONTANA POWER COMPANY COMBINED BALANCE SHEET ASSETS
UNAUDITED DECEMBER 31, ---------- ----------------------- 9/30/2001 2000 1999 ------------------------------------ (Thousands of Dollars) CURRENT ASSETS: Cash and cash equivalents ............ $ 6,504 $ -- $ 443,036 Temporary cash investments ........... -- -- 40,417 Accounts receivable: Unrelated, net of allowances ...... 54,439 135,424 99,159 Related ........................... 55,909 76,883 214,454 Materials and supplies (principally at average cost) ..................... 11,508 11,287 11,270 Notes receivable: Unrelated ......................... 247 254 -- Related ........................... 3,563 50,863 -- Prepayments and other assets ......... 51,516 48,513 42,862 Prepaid income taxes ................. 37,564 11,050 -- Deferred income taxes ................ 17,054 17,054 4,714 ------------------------------------ 238,304 351,328 855,912 PROPERTY PLANT AND EQUIPMENT: Plant, less accumulated depreciation, depletion, and amortization ....... 1,092,178 1,089,329 1,085,250 OTHER ASSETS: Intangibles .......................... 7,561 7,988 -- Investments .......................... 25,439 25,937 24,504 Regulatory assets related to income taxes ............................. 56,929 60,423 60,538 Regulatory assets - other ............ 164,570 142,434 150,486 Other deferred charges ............... 4,972 7,347 47,654 ------------------------------------ 259,471 244,129 283,182 TOTAL ASSETS ............................ $1,589,953 $1,684,786 $2,224,344 ====================================
The accompanying notes are an integral part of these financial statements. 3 THE UTILITY OF THE MONTANA POWER COMPANY COMBINED BALANCE SHEET LIABILITIES AND EQUITY
UNAUDITED DECEMBER 31, ---------- ----------------------- 9/30/2001 2000 1999 ------------------------------------ (Thousands of Dollars) CURRENT LIABILITIES: Accounts payable: Unrelated ........................... $ 37,162 $ 72,919 $ 24,172 Related ............................. 75,809 77,487 82,754 Dividends payable ...................... 1,460 1,456 22,746 Income taxes payable ................... -- -- 115,784 Other taxes payable .................... 40,195 30,827 34,922 Regulatory liability - oil and natural gas sale ............................ 30,427 32,549 -- Short-term borrowing: Unrelated ........................... 74,600 75,000 -- Related ............................. 49,811 49,372 49,998 Long-term debt due within one year ..... 6,930 67,715 47,148 Interest accrued ....................... 9,539 5,895 11,890 Other current liabilities .............. 53,395 62,403 47,654 ------------------------------------ 379,328 475,623 437,068 LONG-TERM LIABILITIES: Deferred income taxes .................. 86,422 81,004 82,283 Investment tax credits ................. 12,829 13,163 13,330 Deferred revenue ....................... 38,329 42,381 92,262 Net proceeds from the generation sale .. 215,194 214,887 219,726 Other deferred credits ................. 114,595 67,814 85,503 ------------------------------------ 467,369 419,249 493,104 LONG-TERM DEBT: Long-term debt ......................... 306,188 309,463 597,468 Company obligated mandatorily redeemable preferred securities of subsidiary trust ............................... 65,000 65,000 65,000 ------------------------------------ 371,188 374,463 662,468 EQUITY: Preferred stock ........................ 57,654 57,654 57,654 Other equity ........................... 314,414 357,797 574,050 ------------------------------------ 372,068 415,451 631,704 TOTAL LIABILITIES AND EQUITY ........... $1,589,953 $1,684,786 $2,224,344 ====================================
The accompanying notes are an integral part of these financial statements. 4 THE UTILITY OF THE MONTANA POWER COMPANY COMBINED STATEMENT OF CASH FLOWS
UNAUDITED NINE MONTHS ENDED YEAR ENDED DECEMBER 31, --------- ----------------------------------- 9/30/2001 2000 1999 1998 ------------------------------------------------ (Thousands of Dollars) NET CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) .................................. $ (41,910) $ 6,805 $ 68,042 $ 56,810 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization ................... 42,765 54,123 69,694 71,580 Deferred income taxes ........................... 8,578 (13,671) (188,570) (4,252) Losses (gains) on sales of property and investments .............................. -- -- (59) 3,372 Other noncash charges to net income - net ................................. (6,478) 3,807 11,364 17,718 Changes in assets and liabilities: Accounts and notes receivable - unrelated ................................. 80,992 (36,519) 62,183 (47,780) Accounts and notes receivable - related ................................... 68,274 86,708 (131,293) (63,636) Income taxes payable ......................... -- (115,784) 106,948 6,461 Prepaid income taxes ......................... (26,514) (11,050) -- -- Accounts payable - unrelated ................. (35,757) 48,747 2,033 (16,000) Accounts payable - related companies ......... (1,678) (5,267) 50,720 21,934 Deferred revenue ............................. (4,052) (49,881) 92,262 -- Miscellaneous temporary investments ............................... -- 40,417 (40,417) -- Shared proceeds - oil and natural gas sale .......................... 2,122 32,549 -- -- Generation asset sale - net proceeds ......... 307 (4,839) 219,726 -- Other assets and liabilities - net ....................................... 30,382 19,664 24,213 20,122 ------------------------------------------------ Net cash provided by operating activities ...................................... 117,031 55,809 346,846 66,329
The accompanying notes are an integral part of these financial statements. 5 THE UTILITY OF THE MONTANA POWER COMPANY COMBINED STATEMENT OF CASH FLOWS (CONT.)
UNAUDITED NINE MONTHS ENDED YEAR ENDED DECEMBER 31, ------------------------------------------------ 9/30/2001 2000 1999 1998 ------------------------------------------------ (Thousands of Dollars) NET CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures .......................... (44,796) (77,867) (79,575) (94,461) Proceeds from sales of property and investments ................................ 84 (1,091) 514,844 (2,841) Advances to related companies ................. -- (99,000) -- (20,001) Additional investments ........................ 498 (1,433) (345) (6,843) ------------------------------------------------ Net cash (used for) provided by investing activities .................... (44,214) (179,391) 434,924 (124,146) NET CASH FLOWS FROM FINANCING ACTIVITIES: Purchase of The Montana Power Company treasury stock ............................. -- (60,784) (144,872) -- Dividends from related companies .............. -- -- 138,900 6,500 Issuance of The Montana Power Company common stock ............................... 590 2,384 357 7,950 Dividends paid ................................ (2,768) (67,053) (90,902) (91,598) Issuance of long-term debt .................... -- 36,990 23,074 129,334 Retirement of long-term debt .................. (64,174) (305,365) (145,201) (46,024) Net change in short-term borrowing - unrelated .................................. (400) 75,000 -- (69,100) Net change in short-term borrowing - related .................................... 439 (626) (123,296) 123,961 ------------------------------------------------ Net cash (used for) provided by financing activities ................. (66,313) (319,454) (341,940) 61,023 ------------------------------------------------ INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . 6,504 (443,036) 439,830 3,206 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ... -- 443,036 3,206 -- ------------------------------------------------ CASH AND CASH EQUIVALENTS, END OF PERIOD ......... $ 6,504 $ -- $ 443,036 $ 3,206 ================================================ SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid for: Income taxes, net of refunds ............... $ 100,015 $ 132,944 $ 126,514 $ 27,635 Interest ................................... 23,179 44,419 56,356 62,470
The accompanying notes are an integral part of these financial statements. 6 THE UTILITY OF THE MONTANA POWER COMPANY STATEMENT OF OTHER EQUITY
UNAUDITED --------- NINE MONTHS ENDED YEAR ENDED DECEMBER 31, ----------------------------------- 9/30/2001 2000 1999 1998 ------------------------------------------------ (Thousands of Dollars) Other equity at beginning of period ........ $ 357,797 $ 574,050 $ 602,493 $ 636,950 Net income .............................. (41,910) 6,805 68,042 56,810 Issuance of The Montana Power Company common stock ................. 590 2,384 357 7,950 Reacquisition of The Montana Power Company common stock ................. -- (60,784) (144,872) -- Dividend on The Montana Power Company common stock ................. -- (62,426) (88,155) (88,008) Dividend on The Montana Power Company preferred stock .............. (2,847) (3,690) (3,690) (3,690) Foreign currency translation adjustments 138 4 48 111 Distributions on unallocated stock held by trustee for retirement savings plan 3,782 3,174 2,897 2,647 Equity transfers and distributions ...... -- (99,000) 138,900 (13,501) Other ................................... (3,136) (2,720) (1,970) 3,224 ------------------------------------------------ Other equity at end of period .............. $ 314,414 $ 357,797 $ 574,050 $ 602,493 ================================================
The accompanying notes are an integral part of these financial statements. 7 NOTES TO THE FINANCIAL STATEMENTS The accompanying combined financial statements of The Utility of The Montana Power Company as of and for the nine months ended September 30, 2001 are unaudited. In the opinion of management, these statements reflect all normally recurring accruals necessary for a fair statement of the results of operations for those interim periods. Results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year, and these financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters that would be included in full fiscal year financial statements. Therefore, these statements should be read in conjunction with our accompanying audited financial statements. When we use the terms "we," "us," or "our" in this financial presentation, we mean the utility operations of The Montana Power Company (MPC) and its wholly owned subsidiaries and business trusts, consisting of The Montana Power Capital I, Discovery Energy Solutions, Inc., Canadian-Montana Pipe Line Corporation, Montana Power Services Company, One Call Locators, LLC, Montana Power Natural Gas Funding Trust, and Colstrip Community Services Company, collectively referred to as the Utility. NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |_| THE MONTANA POWER L.L.C./UTILITY BUSINESS On September 29, 2000, MPC entered into a Unit Purchase Agreement with NorthWestern Corporation (NorthWestern), a South Dakota-based energy company, to purchase its affiliate, The Montana Power, L.L.C. (MPLLC), a Montana limited liability company. As part of the restructuring, MPLLC will own the Utility, including our electric (including Colstrip Unit 4) and natural gas utility business, along with other assets, liabilities, commitments, and contingencies. The consideration for MPLLC is approximately $1,090,000,000, and is comprised of cash of $602,000,000 and NorthWestern's assumption of up to $488,000,000 of debt. The closing is subject to the Montana Public Service Commission (PSC) approval of the utility operations under NorthWestern ownership as a fit, willing, and able provider of adequate service and facilities at just and reasonable rates, and other customary closing conditions. On November 7, 2001, the PSC established January 31, 2002 as the date for issuance of an order. We received approval for the utility sale from the MPC shareholders during a special meeting in September 2001, and regulatory approval from the Federal Energy Regulatory Commission (FERC)in February 2001. Pending receipt of a final, favorable PSC order, we cannot assure that the sale of MPLLC to NorthWestern will be completed or that the terms and conditions will remain unchanged. |_| BASIS OF ACCOUNTING Our accounting policies conform with generally accepted accounting principles. With respect to our utility operations, these policies are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities. |_| PRINCIPLES OF COMBINATION The combined financial statements of the Utility include the utility operations of MPC and MPC's wholly owned subsidiaries Canadian-Montana Pipe Line Corporation, Montana Power Capital I, Montana Power Natural Gas Funding 8 Trust, Colstrip Community Services Company, One Call Locators, LLC, Discovery Energy Solutions, Inc., and Montana Power Services Company. All intercompany transactions and balances have been eliminated in the combination of these entities. These entities are being combined because they represent the entities which will be wholly owned by MPLLC and included as part of the pending sale to NorthWestern discussed above. These entities are commonly owned and controlled by MPC. |_| USE OF ESTIMATES Preparing financial statements requires the use of estimates based on information available. Actual results may differ from our accounting estimates as new events occur or we obtain additional information. |_| CASH AND CASH EQUIVALENTS AND TEMPORARY CASH INVESTMENTS We consider all liquid investments with original maturities of three months or less to be cash equivalents, and investments with original maturities over three months and up to one year as temporary investments. At December 31, 1999, all of our investments were available for sale, and their fair value approximates the value reported on the Combined Balance Sheet. We had no temporary investments at December 31, 2000. |_| ACCOUNTS RECEIVABLE UNRELATED Accounts receivable are presented net of allowance for doubtful accounts of $1,164,000 in 2000 and $1,104,000 in 1999. 9 |_| PROPERTY, PLANT, AND EQUIPMENT The following table provides year-end balances of the major classifications of our property, plant, and equipment, which we record at cost:
DECEMBER 31, -------------------------- 2000 1999 -------------------------- (Thousands of Dollars) Electric Plant: Generation (including our share of jointly owned) ........................... $ 54,477 $ 53,453 Transmission ................................ 412,885 405,062 Distribution ................................ 604,070 573,531 Other Electric .............................. 135,477 133,720 Natural Gas Plant: Production and storage ...................... 71,681 71,440 Transmission ................................ 167,416 163,968 Distribution ................................ 151,039 147,764 Other Natural Gas ........................... 39,841 51,658 Nonutility Plant ............................... 6,265 2,750 -------------------------- Total Plant .............................. 1,643,151 1,603,346 Less: Accumulated depreciation and amortization ............................ 553,822 518,096 -------------------------- Net plant ................................ $1,089,329 $1,085,250 ==========================
We capitalize the cost of plant additions and replacements, including an allowance for funds used during construction (AFUDC) of utility plant. We determine the rate used to compute AFUDC in accordance with a formula established by FERC. This rate averaged 8.6 percent for 2000, 7.1 percent for 1999, and 8.3 percent for 1998. We charge costs of utility depreciable units of property retired, plus costs of removal less salvage, to accumulated depreciation and recognize no gain or loss. We recognize gain or loss upon the sale or other disposition of nonutility property. We charge maintenance and repairs of plant and property, as well as replacements and renewals of items determined to be less than established units of plant, to operating expenses. Included in the plant classifications are utility plant under construction in the amounts of $2,637,000 and $3,876,000 for 2000 and 1999, respectively. We record provisions for depreciation at amounts substantially equivalent to calculations made on straight-line and unit-of-production methods by applying various rates based on useful lives of properties determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provisions for depreciation of utility plant was approximately 3.5 percent for 2000 and 3.0 percent for 1999. 10 |_| JOINTLY OWNED ELECTRIC PLANT Prior to the December 17, 1999 sale of the electric generating assets discussed in Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets," we were a joint-owner of Colstrip Units 1, 2, and 3. We owned 50 percent of Units 1 and 2 and 30 percent of Unit 3. We continue to own a leasehold interest in 30 percent of Colstrip Unit 4. We also own an approximate 30-percent interest in the transmission facilities serving these units. At December 31, 2000, our investment in these facilities was $132,331,000 and the related accumulated depreciation was $48,103,000. Each joint-owner provides its own financing. Our share of direct expenses associated with the operation and maintenance of these joint facilities, including Colstrip Units 1, 2, and 3 through December 17, 1999, is included in the corresponding operating expenses in the Combined Statement of Income. |_| REVENUE AND EXPENSE RECOGNITION We record operating revenues monthly on the basis of consumption or service rendered. To match revenues with associated expenses, we accrue unbilled revenues for electric and natural services delivered to customers but not yet billed at month-end. The Emerging Issues Task Force (EITF) Issue No. 98-10 requires that energy contracts entered into under "trading activities" be marked to market with the gains or losses shown net in the income statement. EITF 98-10 became effective for fiscal years beginning after December 15, 1998. We adopted EITF 98-10 as of January 1, 1999, and accordingly mark to market energy contracts that qualify as "trading activities." The cumulative effect of adopting EITF 98-10 had no material effect on our combined financial position, results of operations, or cash flows. |_| REGULATORY ASSETS AND LIABILITIES For our regulated operations, we follow SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Pursuant to this pronouncement, certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to the customers. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. 11
DECEMBER 31, -------------------------------------------- 2000 1999 ASSETS LIABILITIES ASSETS LIABILITIES -------------------------------------------- (Thousands of Dollars) Income taxes ................... $ 58,452 $ -- $ 57,526 $ -- Colstrip Unit 3 carrying charge ...................... 38,337 -- 38,494 -- Conservation programs .......... 27,956 -- 28,378 -- Competitive transition charges (CTCs) .............. 50,965 -- 53,768 -- Generation net proceeds in excess of book value ........ -- 214,887 -- 219,726 Proceeds from oil and natural gas sale ............ -- 32,549 -- -- Investment tax credits ......... -- 13,163 -- 13,330 Other .......................... 40,384 18,816 44,646 12,178 -------------------------------------------- Subtotal .................... 216,094 279,415 222,812 245,234 Less: Current portions ............ 13,237 34,979 11,788 3,402 -------------------------------------------- Total .................... $202,857 $244,436 $211,024 $241,832 ============================================
Income taxes reflect the effects of temporary differences that we will recover in future rates. In August 1985, the PSC issued an order allowing us to recover deferred carrying charges and depreciation expenses over the remaining life of Colstrip Unit 3. These recoveries compensated us for unrecovered costs of our investment for the period from January 10, 1984 to August 29, 1985, when we placed the plant in service. We were amortizing this asset to expense and recovering $1,831,000 in rates per year. Conservation programs represent our Demand Side Management programs, which are in rate base and which we were amortizing to income over a 10-year period. We are recovering the CTCs, which relate to natural gas properties that we removed from regulation on November 1, 1997, through rates over 15 years. Investment tax credits and account balances included in "Other" represent items that we are amortizing currently or are subject to future regulatory confirmation. For information regarding the proceeds from the oil and natural gas sale, see Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets," under the "Natural Gas Rates" section. With the sale of the electric generating assets, it is our position that any of these amounts related to electric supply should be recovered from sale proceeds in excess of book value. Amortization of these assets stopped in February 2000 when the expenses were removed from rates. For further information on the effects of the sale of our electric generating assets, see Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets." |_| STORM DAMAGE AND ENVIRONMENTAL REMEDIATION COSTS When losses from costs of storm damage and environmental remediation obligations for our utility operations are probable and reasonably estimable, we charge these costs against established, approved operating reserves. The reserves' balance was approximately $11,080,000 at December 31, 2000 and approximately $11,166,000 at December 31, 1999. We have included these reserves in "Other current liabilities" on the Combined Balance Sheet. |_| INCOME TAXES We are included in a consolidated United States income tax return filed by MPC. MPC allocates consolidated United States income taxes to utility and nonutility operations as if MPC filed separate United States income tax returns for each operation. We defer income taxes to provide for the temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. For further information on income taxes, see 12 "Regulatory Assets and Liabilities" mentioned above and Note 4, "Income Tax Expense." |_| DEFERRED REVENUES We defer revenues to account for the timing differences between cash received and revenues earned and reflect these amounts on the Combined Balance Sheet in "Deferred revenue." We reflect the current portion of these amounts in "Other current liabilities" on the Combined Balance Sheet. We are recognizing a prepayment received in December 1999 from the Los Angeles Department of Water and Power in revenues over the original term of the agreement, approximately 11 years. |_| ASSET IMPAIRMENT In accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," we periodically review long-lived assets for impairment whenever events or changes in circumstances indicate that we may not recover the carrying amount of an asset. |_| COMPREHENSIVE INCOME Comprehensive income consists of net income (loss) and other comprehensive income (loss). For the years ended December 31, 2000, 1999, and 1998, our only item of other comprehensive income was foreign currency translation adjustments of the assets and liabilities of Canadian-Montana Pipe Line Corporation. These adjustments resulted in increases to other equity of $3,500, $48,300, and $111,000 in 2000, 1999, and 1998, respectively. |_| DERIVATIVE FINANCIAL INSTRUMENTS ELECTRIC SWAP AGREEMENTS Long-term power supply agreements, primarily one with a large industrial customer, exposed us to commodity price risk. We were exposed to this risk to the extent that a portion of the electric energy we were required to sell to our industrial customers at fixed rates was purchased at prices indexed to a wholesale electric market, which can be higher than the fixed sales rate that we received pursuant to our power supply agreements. We mitigated our exposure to losses on these agreements with financial derivative instruments called "price swaps" and offsetting electric energy purchase and sales agreements. Since June 1998, we have had a price swap agreement with one of our industrial customers that converts 43 MWs of the Mid-Columbia (Mid-C) index price of our supply agreement with that customer to a fixed price through May 2001. In fiscal year 2000, we also entered into another price swap with a counterparty that effectively hedged 35 MWs of the anticipated market-based purchases to supply that agreement through March 2001. In accordance with the provisions of SFAS No. 80, "Accounting for Futures Contracts," we recognized gains and losses from the financial swaps in the same period in which we recognized the sales and related purchases under that agreement. For fiscal year 2000, we recognized a net gain of approximately $16,000,000 from these financial swaps and losses of approximately $32,200,000 from supplying large industrial customers. For more specific information about the commodity price risk that we face as a result of our long-term power supply agreements, see Note 11, "Contingencies," in the "Long-Term Power Supply Agreements" section. 13 An estimate of the fair market value of the swaps based on the Mid-C forward prices of December 29, 2000 aggregated a gain of approximately $21,800,000 as of December 31, 2000, which would offset approximately 40 percent of the expected losses on the above power supply agreements. Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Transactions and Hedging Activities." These pronouncements expand the definition of a derivative and require that all derivative instruments be recorded as assets or liabilities on an entity's balance sheet at fair value. Accounting for gains and losses resulting from changes in the fair value of those derivatives is dependent on the use of the derivative and whether it qualifies for hedge accounting. For further discussion on the effects of SFAS No. 133, see Note 17, "Nine Months Ended September 30, 2001 (Unaudited)," under the "Derivative Financial Instruments" section. At January 1, 2001, we had price swap agreements that hedged our exposure to variability in expected cash flows attributable to commodity price risk. Specifically, long-term power supply agreements, primarily one with a large industrial customer, expose us to that risk, to the extent that a portion of the electric energy we are required to sell to our industrial customers at fixed rates is purchased at prices indexed to the Mid-Columbia (Mid-C) wholesale electric market, which can be higher than the fixed sales rates. Another agreement to sell 1,760,000 dekatherms of natural gas storage at a monthly price based on the Alberta Energy Company "C" Hub (AECO-C) index, from October 2000 to March 2001, exposed us to adverse fluctuation in that market price index. In accordance with the provisions of SFAS No. 133, we marked to market at January 1, 2001 our price swap agreements hedging these forecasted electric energy and natural gas sales, with a corresponding credit entry to "Other comprehensive income" for approximately $18,800,000 before income taxes. That entry represented our cumulative transition adjustment in adopting SFAS No. 133. NATURAL GAS UTILITY SWAPS By drilling wells and adding compression at our Cobb storage reservoir, we were able to sell natural gas that had been held in reserve to provide firm storage deliverability to our customers. We therefore contracted to sell, from October 2000 through March 2001, 1,760,000 dekatherms from that reservoir at a monthly price based on the Alberta Energy Company "C" Hub (AECO-C) index. To reduce our exposure to fluctuations of the market index price, we entered into a swap agreement with a counterparty that effectively converted that index price to a fixed price for 903,000 dekatherms associated with these sales from December 2000 through February 2001. For December 2000, we recognized a loss of approximately $300,000 on the swap and a profit of approximately $1,200,000 on the sale of the Cobb storage natural gas. Based on the AECO-C forward prices at December 29, 2000, we estimated a loss of approximately $3,000,000 on the swap to offset profits of $4,900,000 on the sale through February 2001. We deferred the net profit of these transactions in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," and will recognize this amount in income as amounts are reflected in rates. 14 |_| FAIR VALUE OF FINANCIAL INSTRUMENTS
2000 1999 ----------------------------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE ----------------------------------------- (Thousands of Dollars) ASSETS: Investments ..................... $ 25,901 $ 25,901 $ 24,468 $ 24,468 LIABILITIES: Company obligated mandatorily redeemable preferred securities ................... $ 65,000 $ 65,000 $ 65,000 $ 63,206 Long-term debt (including due within one year) ............. 377,179 377,563 644,615 622,800
The following methods and assumptions were used to estimate fair value: o Investments - The carrying value of most of the investments approximates fair value as they have short maturities or the carrying value equals their cash surrender value. The investments consist mainly of the cash value of insurance policies associated with an unfunded, nonqualified benefit plan for senior management, executives, and directors and funds deposited with the trustee of our securitization bonds discussed in Note 8, "Long-Term Debt." o Mandatorily redeemable preferred securities and long-term debt - The fair value was estimated using quoted market rates for the same or similar instruments. Where quotes were not available, fair value was estimated by discounting expected future cash flows using year-end incremental borrowing rates. NOTE 2 - DEREGULATION, REGULATORY MATTERS, AND 1999 SALE OF ELECTRIC GENERATING ASSETS |_| DEREGULATION The electric and natural gas utility businesses in Montana are transitioning to a competitive market in which commodity energy products and related services are sold directly to wholesale and retail customers. ELECTRIC Montana's Electric Utility Industry Restructuring and Customer Choice Act (Electric Act), passed in 1997, provides that all customers will be able to choose their electric supplier by July 1, 2002, with our electric utility acting as default supplier through the transition period. As default supplier, we are obligated to continue to supply electric energy to customers in our service territory who have not chosen, or have not had an opportunity to choose, other power suppliers during the transition period. This obligation requires us to develop an energy supply portfolio to meet these customers' electric needs. Buyback contracts with PPL Montana, LLC (PPL Montana), the purchaser of our former electric generating assets, allow us to purchase power necessary to serve these customers through the transition period ending June 30, 2002. In its 2001 session, the Montana Legislature passed House Bill 474 (HB 474), which extends the transition period through June 30, 2007. This law also provides for the use of a cost-recovery mechanism that ensures all prudently incurred electric energy supply costs of the default supplier are fully 15 recoverable in rates. Initiative 117, which if passed, would repeal HB 474, has been approved for inclusion on the November 2002 ballot in Montana. In the event that HB 474 is repealed, Montana Law would continue the transition period through at least June 30, 2007, and provide full cost recovery. On October 29, 2001, we filed with the PSC our default supply portfolio, containing a mix of long and short-term contracts that we negotiated in order to provide electricity to default supply customers. This filing seeks approval of the default supply portfolio contracts and establishment of default supply rates for customers who have not chosen alternative suppliers by July 1, 2002. We expect that the costs of the supply portfolio and a competitive transition charge for out-of-market Qualifying Facility (QF) costs, as discussed below, will increase residential electric rates by approximately 20 percent beginning July 1, 2002. If the PSC does not approve our default supply portfolio, we may be required to seek alternative sources of supply. While we believe that we have met our default supply obligations prudently, the PSC could also disallow the recovery of our costs incurred in entering into the default supply portfolio if a determination is made that the contracts were not entered into prudently. On that same day, we submitted an updated Tier II filing with the PSC, addressing the recovery of transition costs of generation assets and other power-purchase contracts, generation-related regulatory asset transition costs, and transition costs associated with the out-of-market QF power-purchase contract costs. Previously, we initiated litigation in Montana District Court in Butte to address our ability to use tracking mechanisms to ensure fair and accurate recovery of these costs. Although the District Court ruled that the PSC must allow us to incorporate tracking mechanisms in our transition plan proposal, the Montana Supreme Court reversed this decision on appeal by the PSC and the Large Customer Group, which consists of various large industrial customers. Without the ability to use tracking mechanisms, we have established the amount of our remaining net transition costs, after consideration of generation sale proceeds in excess of book value, as our out-of-market QF costs of approximately $304,700,000, on a net present value basis. While the PSC will establish procedural schedules to process both the default supply and Tier II filings, we have proposed July 1, 2002 as the date that rates from these filings become effective. If the PSC does not permit the recovery of these costs through an annual competitive transition charge, we may be required to write-off our transition costs which could have, depending on the amount and timing of the disallowance, a material adverse impact on our results of operation and financial condition. NATURAL GAS Montana's Natural Gas Utility Restructuring and Customer Choice Act, also passed in 1997, provides that a natural gas utility may voluntarily offer its customers choice of natural gas suppliers and provide open access. We have opened access on our gas transmission and distribution systems, and all of our natural gas customers have the opportunity of gas supply choice. |_| REGULATORY MATTERS The PSC regulates our transmission and distribution services and approves the rates that we charge for these services, while FERC regulates our transmission services and our remaining generation operations. Current regulatory issues are discussed below. 16 PENDING SALE OF MPLLC Together with NorthWestern, MPC filed joint applications with FERC on December 20, 2000 and with the PSC on January 11, 2001 seeking approval of the sale of our utility business to NorthWestern. FERC issued its approval on February 20, 2001. The PSC issued an order in June 2001 denying the joint application, claiming that insufficient information had been provided for it to fully evaluate whether the transaction is in the public interest. The PSC itemized additional information that must be provided before processing of the case will continue. MPC re-filed the joint application with the PSC in August 2001 and the PSC established a procedural schedule setting January 31, 2002 as the date for issuance of an order. While MPC expects the PSC will approve the sale of our utility business to NorthWestern, pending receipt of a final, favorable PSC order, they cannot assure that the sale of MPLLC to NorthWestern will be completed or that the terms and conditions will remain unchanged. PENDING TRANSMISSION ASSET SALE In accordance with our Asset Purchase Agreement with PPL Montana, we expect to sell our portion of the 500-kilovolt transmission system associated with Colstrip Units 1, 2, and 3 for $97,100,000, subject to the receipt of required regulatory approvals. We expect this transaction to close shortly after the pending sale of MPLLC to NorthWestern closes. PSC ELECTRIC RATES In August 2000, we filed a combined request for increased electric and natural gas rates with the PSC, requesting increased annual electric transmission and distribution revenues of approximately $38,500,000, with a proposed interim annual increase of approximately $24,900,000. On November 28, 2000, the PSC granted us an interim electric rate increase of approximately $14,500,000, with hearings on this submission beginning in January 2001. On May 8, 2001, we received a final order from the PSC resulting in an annual delivery service revenue adjustment of $16,000,000, including the $14,500,000 interim increase granted on November 28, 2000. On June 27, 2001, the PSC issued an order stating that they continue to have jurisdiction over us as a fully integrated public utility, in spite of the December 17, 1999 sale of our electric generating facilities. The order requires that, if we desire a power supply rate change at the end of the rate moratorium on July 1, 2002, we must make a filing containing information that supports what rates would be if the regulatory system in place prior to deregulation remained intact. We filed a motion for reconsideration with the PSC, which was subsequently denied. We have since filed a complaint against the PSC in Helena District Court, disputing this order. We cannot predict the ultimate outcome of this matter or its potential effect on our financial position or results of operation. NATURAL GAS RATES As discussed above, in August 2000, we filed a combined request for increased natural gas and electric rates with the PSC. We requested increased annual natural gas revenues of approximately $12,000,000, with a proposed interim annual increase of approximately $6,000,000. On November 28, 2000, the PSC granted us an interim natural gas rate increase of approximately $5,300,000. On May 8, 2001, we received a final order from the PSC resulting in an annual delivery and gas storage service revenue increase of $4,300,000. Because the amount established in the final order was less than the interim order, we began including a credit for the difference collected from November 2000 17 through May 2001, with interest, in our customers' bills over a six-month period starting October 1, 2001. In January 2001, we submitted to the PSC an Annual Gas Cost Tracker requesting an increase of approximately $51,000,000. At that time, we also submitted a Compliance Filing for a credit of approximately $32,500,000 associated with a sharing of the proceeds from the sale of gathering and production properties previously included in the natural gas utility's rate base. As a result, effective February 1, 2001, we began collecting a net amount of approximately $18,500,000 in revenues over a one-year period. In September 2001, after all testimony addressing the amount of sharing had been filed with the PSC, we reached an agreement with intervening parties to increase the amount of the credit to approximately $56,300,000. This $23,800,000 increase, along with approximately $5,300,000 in interest from the date of sale, will be credited to customers' bills over a two-year period beginning January 1, 2002. On December 7, 2001, we filed our Annual Gas Cost Tracker request with the PSC for the tracking year beginning November 1, 2001. FERC Through a filing with FERC in April 2000, we are seeking recovery of approximately $23,800,000 in transition costs associated with serving two wholesale electric cooperatives. We do not expect a FERC decision on this filing, which corresponds with our transition-costs recovery proceedings with the PSC in Montana, until after the PSC issues its Tier II order. |_| 1999 SALE OF ELECTRIC GENERATING ASSETS ASSETS SOLD On December 17, 1999, in accordance with the Asset Purchase Agreement entered into with PPL Montana, MPC sold substantially all of our electric generating assets and related contracts. MPC also sold an immaterial amount of associated transmission assets, totaling less than 40 miles. The asset sale did not include the Milltown Dam near Missoula, Montana (gross capacity of approximately 3 MWs) or any of our QF purchase-power contracts. It also did not include our leased share of the Colstrip Unit 4 generation or transmission assets. As expected, the sale of our electric generating assets in December 1999 reduced the Utility's net income for 2000. Utility revenues decreased because of discontinued off-system revenues that related to the electric generating assets sold. In addition, we no longer earn a return on our shareholders' investment in the electric generating assets. Before the sale, revenues covered the costs of operating the generating plants, taxes and interest, and earned a return on our shareholders' investment. Since the sale, we continue to bill our core customers for energy supply, but now these revenues recover the costs of the power that we purchase to serve these customers. The energy that we formerly generated and sold to core customers is now purchased pursuant to buyback contracts. The maximum price that we pay for power in the buyback contracts, $22.25/MWh, represents our net fully allocated supply costs of service in current rates, replacing operations and maintenance expense, property tax expense, depreciation expense, and return on investment associated with the electric generating assets. In the sale of these assets, we generally retained all pre-closing obligations, and the purchaser generally assumed all post-closing obligations. However, with respect to environmental liabilities, the purchaser assumed all pre-closing (with certain limited exceptions) and post-closing environmental liabilities associated with the purchased assets. 18 While the purchaser assumed pre-closing environmental liabilities, we agreed to indemnify the purchaser from these pre-closing environmental liabilities, including a limited indemnity obligation for losses arising from required remediation of pre-closing environmental conditions, whether known or unknown at the closing, limited to: o 50 percent of the loss. (Our share of this indemnity obligation at the Colstrip Project is limited to our pro-rata share of this 50 percent based on our pre-sale ownership share.) o A two-year period after closing for unknown conditions. The indemnity for required remediation of pre-closing conditions known at the time of the closing continues indefinitely. o An aggregate amount no greater than 10 percent of the purchase price paid for the assets. In December 2000, we received a claim notice related to this indemnity obligation. Based on available information, we do not expect this indemnity claim on the indemnity obligation to have a material adverse effect on our combined financial position, results of operations, or cash flows. CASH PROCEEDS At December 31, 1999, we recorded a regulatory liability and related deferred income tax to reflect the generation sale proceeds in excess of book value. The Company's current estimate of this liability, which will ultimately be determined in the Tier II docket, is approximately $215,000,000 before income taxes. This liability represents a deferral of the gain on the generation sale and nothing has been reflected in the Statement of Income. As part of our Tier II filing, we plan to deduct from the regulatory liabilities approximately $22,000,000 of other generation-related transition costs and approximately $65,600,000 of regulatory asset transition costs. The other generation-related transition costs consist mainly of Selling, General, and Administrative costs and costs to retire debt. The regulatory asset transition costs consist mainly of capitalized conservation costs and carrying charges associated with Colstrip Unit 3. We have used a portion of the net cash proceeds received (excluding the proceeds in excess of book value) to purchase treasury shares of MPC's common stock, to reduce debt, and to fund projects involving expansion of Touch America, a wholly owned subsidiary of MPC. EFFECT ON 1999 EARNINGS The asset sale affected positively our electric utility's 1999 earnings through the reversal of approximately $3,000,000 (after taxes) in interest expense recorded in prior years relating to Kerr Project liabilities and through recognition of approximately $10,000,000 in Investment Tax Credits. NOTE 3 - RELATED PARTY TRANSACTIONS |_| COAL PURCHASES AND TRANSPORTATION We purchased significant quantities of coal from Western Energy, which was a subsidiary of MPC through April 2001, under two long-term coal contracts. We also had a long-term contract with Western Energy to transport some of this coal. Purchases under these contracts were $10,372,000, $39,729,000, and $38,796,000 for the years ending December 31, 2000, 1999, and 1998, respectively. As a result of the 19 December 1999 sale of substantially all of our electric generating assets, long-term coal purchase contracts associated with Colstrip Units 1, 2, and 3 were transferred to PPL Montana. |_| SALES OF ELECTRICITY TO COAL We sold electric energy to Western Energy primarily for use in the operations of their Rosebud mine in Colstrip, Montana. For the three years ended December 31, 2000, these related sales amounted to approximately $3,300,000 per year. |_| OIL AND NATURAL GAS PURCHASES We purchased natural gas through October 2000 from MP Gas, MPC's former subsidiary. Total purchases from MP Gas were $11,561,000, $16,651,000, and $17,874,000 for the years ending December 31, 2000, 1999, and 1998, respectively. |_| MPT&M ELECTRIC SALES Prior to the December 1999 electric generating asset sale, we sold excess electric energy to The Montana Power Trading & Marketing Company (MPT&M). MPT&M then sold the excess energy in the secondary markets. For the years ended December 31, 1999 and 1998, sales were approximately $59,200,000 and $29,100,000. |_| INTEREST INCOME & EXPENSE During 2000, 1999, and 1998, we earned approximately $2,639,000, $1,547,000, and $1,568,000, respectively, of interest income from outstanding notes receivables with MPC's nonutility subsidiaries. We also incurred interest expense of approximately $2,748,000, $7,014,000, and $3,368,000 for the same periods from outstanding notes payable with MPC's nonutility subsidiaries. |_| RECEIVABLES AND PAYABLES Related party receivables primarily result from either services we provide to, or payments we make on behalf of, MPC's nonutility subsidiaries. Related party payables primarily result from services that we receive from MPC's nonutility subsidiaries.
DECEMBER 31, ------------------------- 2000 1999 ------------------------- (Thousands of Dollars) Accounts receivable: Entech ...................................... $ 17,030 $ 117,355 Telecommunications .......................... 39,065 2,847 Oil and Gas ................................. -- 90,541 Coal ........................................ 20,343 5,184 Continental Energy Services ................. 445 (1,473) ------------------------- $ 76,883 $ 214,454 Notes receivable: Entech ...................................... 48,596 -- Continental Energy Services ................. 2,267 -- ------------------------- $ 50,863 $ -- Accounts payable: Entech ...................................... 73,509 74,595 Telecommunications .......................... 2,180 -- Oil and Gas ................................. -- 2,191 Coal ........................................ 1,798 5,485 Continental Energy Services ................. -- 483 ------------------------- $ 77,487 $ 82,754 Short-term borrowing: Continental Energy Services ............... $ 49,372 $ 49,998
20 NOTE 4 - INCOME TAX EXPENSE Income (loss) before income taxes was as follows:
YEAR ENDED DECEMBER 31, ----------------------------------- 2000 1999 1998 ----------------------------------- (Thousands of Dollars) United States ........................ $ (12,794) $ 81,937 $ 84,237
Income tax expense (benefit) as shown in the Combined Statement of Income consists of the following components:
YEAR ENDED DECEMBER 31, ----------------------------------- 2000 1999 1998 ----------------------------------- (Thousands of Dollars) Current: United States ....................... $ 102 $ 193,192 $ 23,319 Canada .............................. 16 17 18 State ............................... (2,216) 39,186 7,175 ----------------------------------- (2,098) 232,395 30,512 ----------------------------------- Deferred: United States ....................... (16,625) (183,546) (2,427) Canada .............................. -- -- -- State ............................... (876) (34,954) (658) ----------------------------------- (17,501) (218,500) (3,085) ----------------------------------- $ (19,599) $ 13,895 $ 27,427 ===================================
The provision (benefit) for income taxes differs from the amount of income tax determined by applying the applicable U. S. statutory federal rate to pretax income as a result of the following differences:
YEAR ENDED DECEMBER 31, ----------------------------------- 2000 1999 1998 ----------------------------------- (Thousands of Dollars) Computed "expected" income tax expense (benefit) .................... $ (4,478) $ 28,678 $ 29,483 Adjustments for tax effects of: Tax credits .......................... (167) (20,489) (1,362) State income tax, net ................ (5,089) 1,342 4,215 Reversal of utility book/tax depreciation ...................... 3,771 5,399 2,750 Federal credits ...................... (7,309) -- -- Resolution of tax contingencies ...... (4,284) -- -- Other ................................ (2,043) (1,035) (7,659) ----------------------------------- Actual income tax expense (benefit) ..... $ (19,599) $ 13,895 $ 27,427 ===================================
Under Montana regulations, certain tax benefits flow through to customers on a basis consistent with the accelerated deduction of expenses for income tax purposes. As such, when these expenses are recognized for financial reporting purposes, there is not an offsetting tax savings. Our utility's effective tax rate is higher than the statutory rate due to this timing difference. During periods of low income, the income taxes will appear higher than expected. 21 Deferred tax liabilities (assets) are comprised of the following at December 31:
2000 1999 ------------------------- (Thousands of Dollars) Plant related .................................. $ 227,980 $ 220,532 Other .......................................... 36,771 40,591 ------------------------- Gross deferred tax liabilities ............. 264,751 261,123 Amortization of gain on sale/leaseback ......... (10,969) (11,649) Investment tax credit amortization ............. (14,056) (14,056) Electric Generation Sale ....................... (98,557) (101,413) Income Stabilization Adjustments ............... (40,738) (40,738) Other .......................................... (36,481) (15,698) ------------------------- Gross deferred tax assets .................. (200,801) (183,554) Net deferred tax liabilities ............... $ 63,950 $ 77,569 =========================
The change in net deferred tax liabilities differs from current year 2000 deferred tax expense as a result of the following:
Thousands of Dollars ---------- Change in deferred tax ........................................ $(13,619) Regulatory assets related to income taxes ..................... (35) Amortization of investment tax credits ........................ (166) Regulatory asset related to sale of Generation ................ (3,681) -------- Deferred tax expense ....................................... $(17,501) ========
NOTE 5 - PREFERRED STOCK MPC has 5,000,000 authorized shares of preferred stock. MPC cannot declare or pay dividends on its common stock while it has not either declared and set apart cumulative dividends or paid dividends on any of its preferred stock. MPC's preferred stock is in three series as detailed in the following table:
SHARES ISSUED THOUSANDS STATED AND AND OUTSTANDING OF DOLLARS LIQUIDATION --------------------------------------------------------------------- SERIES PRICE* 2000 1999 2000 1999 - -------------------------------------------------------------------------------------------------------------- $6.875 $100 360,800 360,800 $36,080 $36,080 6.00 100 159,589 159,589 15,959 15,959 4.20 100 60,000 60,000 6,025 6,025 Discount -- -- (410) (410) --------------------------------------------------------------------- 580,389 580,389 $57,654 $57,654 ---------------------------------------------------------------------
*Plus accumulated dividends. MPC has the option of redeeming its preferred stock with the consent or affirmative vote of the holders of a majority of the common shares on 30 days notice at $110 per share for our $6.00 Series and $103 per share for our $4.20 Series, plus accumulated dividends. MPC's $6.875 Series is redeemable in whole or in part with the consent or affirmative vote of the holders of a majority of the common shares, at any time on or after November 1, 2003, for a price beginning at $103.438 per share, which decreases annually through October 2013. After that time, the redemption price is $100 per share. 22 At a special meeting of MPC shareholders held on September 21, 2001, shareholders representing more than two-thirds of MPC's outstanding common stock approved (among others) the following proposals: o Holders of Preferred Stock, $6.875 Series, of MPC will receive one share of Touch America Holdings, Inc. Preferred Stock, $6.875 Series, for each share of MPC Preferred Stock. o The redemption of MPC's outstanding Preferred Stock, $4.20 Series, and Preferred Stock, $6.00 Series. NOTE 6 - OTHER EQUITY |_| LLC UNITS Our LLC units represent the MPLLC included in the pending sale to NorthWestern. These entities consist of the utility operations of MPC and MPC's wholly owned subsidiaries Canadian-Montana Pipe Line Corporation, Montana Power Capital I, Montana Power Natural Gas Funding Trust, Colstrip Community Services Company, One Call Locators, LLC, Discovery Energy Solutions, Inc., and Montana Power Services Company. |_| RETIREMENT SAVINGS PLAN MPC has a 401(k) Retirement Savings Plan that covers eligible employees. We contribute, on behalf of the employee, a matching percentage of the amount contributed to the Plan by the employee. In 1990, MPC borrowed $40,000,000 at an interest rate of 9.2 percent to be repaid in equal annual installments over 15 years. The loan was issued under similar terms to the Plan Trustee, which used the proceeds to purchase 3,844,594 shares of MPC's common stock. Shares acquired with loan proceeds are allocated monthly to Plan participants to help meet MPC's matching obligation. The loan, which is reflected as long-term debt (ESOP Notes Payable), is offset by a similar amount in other equity as unallocated stock. MPC's contributions plus the dividends on the shares held under the Plan are used to meet principal and interest payments on the loan with the Plan Trustee. As principal payments on the loan are made, long-term debt and the offset in common shareholders' equity are both reduced. At December 31, 2000, 2,756,662 shares had been allocated to the participants' accounts. We recognized expense for the Plan using the Shares Allocated Method, and the pretax expense was $2,570,000, $3,768,000, and $3,801,000 for 2000, 1999, and 1998, respectively. |_| LONG-TERM INCENTIVE PLAN Under the Long-Term Incentive Plan, MPC has issued options to our employees. Options issued to employees are not reflected in balance sheet accounts until exercised, at which time: (1) authorized, but unissued shares are issued to the employee; (2) the capital stock account is credited with the proceeds; and (3) no charges or credits to income are made. Options were granted at the average of the high and low prices of MPC stock as reported on the New York Stock Exchange composite tape on the date granted and expire ten years from that date. 23 MPC option activity is summarized below:
2000 1999 1998 --------------------------------------------------------------------------------------------------- WTD AVG WTD AVG WTD AVG EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE --------------------------------------------------------------------------------------------------- Outstanding, beginning 3,280,325 $25.63 2,548,094 $22.71 1,081,330 $11.00 of year Granted 1,199,545 34.36 919,510 32.14 2,234,658 24.50 Exercised 149,834 17.07 88,857 10.83 702,562 11.25 Cancelled 253,792 26.88 98,422 24.08 65,332 13.47 --------------------------------------------------------------------------------------------------- Outstanding, end of year 4,076,244 $28.43 3,280,325 $25.63 2,548,094 $22.71 ===================================================================================================
MPC shares under option at December 31, 2000, are summarized below:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE -------------------------------------------------------------------------------- WTD AVG WTD AVG WTD AVG EXERCISE EXERCISE EXERCISE EXERCISE PRICE RANGE SHARES PRICE LIFE SHARES PRICE -------------------------------------------------------------------------------- $10.81 to $11.31 228,099 $11.05 5 yrs 228,099 $11.05 $18.00 to $23.06 472,999 19.48 8 yrs 383,446 18.64 $26.53 to $32.50 2,359,346 28.21 9 yrs 1,507,154 26.62 $35.36 to $38.69 1,015,800 37.00 9 yrs 258 35.36 ---------------- --------------- 4,076,244 2,118,957 ================ ===============
As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation," MPC has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25), and related interpretations in accounting for MPC employee stock options. Under APB 25, because the exercise price of the employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized. Disclosure of pro forma information regarding net income and earnings per share is required by SFAS No. 123. This information has been determined as if MPC had accounted for employee stock options under the fair value method of that statement. The weighted-average fair value of options granted in 2000 and 1999 was $16.35 and $7.03, respectively. MPC employed the binomial option-pricing model to estimate the fair value of each option grant on the date of grant. MPC used the following weighted-average assumptions for grants in 2000 and 1999, respectively: (1) risk-free interest rate of 6.05 percent and 6.35 percent; (2) expected life of 6.2 and 9.8; (3) expected volatility of 42.00 percent and 24.92 percent; and (4) a dividend yield of zero percent and 5.97 percent. Had MPC elected to use SFAS No. 123, MPC's compensation expense would have increased $11,827,000 in 2000, $5,280,000 in 1999, and $795,000 in 1998, a portion of which would have been allocated to the Utility. NOTE 7 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST MPC established Montana Power Capital I (Trust) as a wholly owned business trust to issue common and preferred securities and hold Junior Subordinated Deferrable Interest Debentures (Subordinated Debentures) that we issue. At December 31, 2000 and 1999, the Trust has issued 2,600,000 units of 8.45 percent Cumulative Quarterly Income Preferred Securities, Series A (QUIPS). Holders of the QUIPS are entitled to receive quarterly distributions 24 at an annual rate of 8.45 percent of the liquidation preference value of $25 per security. The sole asset of the Trust is $67,000,000 of our Subordinated Debentures, 8.45 percent Series due 2036. The Trust will use interest payments received on the Subordinated Debentures that it holds to make the quarterly cash distributions on the QUIPS. The QUIPS' $65,000,000 liquidation value is included with Other Long-Term Debt on the Combined Balance Sheet. On or after November 6, 2001, we can wholly redeem the Subordinated Debentures at any time, or partially redeem the Subordinated Debentures from time to time. We also can wholly redeem the Subordinated Debentures if certain events occur before that time. Upon repayment of the Subordinated Debentures at maturity or early redemption, the Trust Securities must be redeemed. In addition, we can terminate the Trust at any time and cause the pro rata distribution of the Subordinated Debentures to the holders of the Trust Securities. Besides our obligations under the Subordinated Debentures, we have agreed to certain Back-up Undertakings. We have guaranteed, on a subordinated basis, payment of distributions on the Trust Securities, to the extent the Trust has funds available to pay such distributions. We also have agreed to pay all of the expenses of the Trust. Considered together with the Subordinated Debentures, the Back-up Undertakings constitute a full and unconditional guarantee of the Trust's obligations under the QUIPS. We are the owner of all the common securities of the Trust, which constitute 3 percent of the aggregate liquidation amount of all the Trust Securities. NOTE 8 - LONG-TERM DEBT The Mortgage and Deed of Trust (Mortgage) imposes a first mortgage lien on all physical properties owned, exclusive of subsidiary company assets and certain property and assets specifically excepted. The obligations collateralized are First Mortgage Bonds, including those First Mortgage Bonds designated as Secured Medium-Term Notes (MTNs) and those securing Pollution Control Revenue Bonds. 25 Long-term debt consists of the following:
DECEMBER 31, ------------------------ 2000 1999 ------------------------ (Thousands of Dollars) First Mortgage Bonds: 71/2% series, due 2001 ........................ $ -- $ 25,000 7% series, due 2005 ........................... 5,386 50,000 81/4% series, due 2007 ........................ 365 55,000 8.95% series, due 2022 ........................ 1,446 50,000 Secured Medium-Term Notes- maturing 2000-2025 7.20%-8.11% ............. 28,000 88,000 Pollution Control Revenue Bonds: City of Forsyth, Montana 6 1/8% series, due 2023 .................... 90,205 90,205 5.90% series, due 2023 ..................... 80,000 80,000 Unsecured Medium-Term Notes: Series A - maturing 2000-2022 8.68%-8.80% ..... -- 17,000 Series B - maturing 2001-2026 7.05%-7.96% ..... 100,000 100,000 Natural Gas Transition Bonds - 6.20%, due 2012 ...................................... 58,412 61,015 ESOP Notes Payable - 9.20%, due 2004 ............. 16,197 19,431 Other ............................................ 27 12,762 Unamortized Discount and Premium ................. (2,859) (3,797) ------------------------ 377,179 644,616 Less: Portion due within one year ................ 67,716 47,148 ------------------------ $ 309,463 $ 597,468 ========================
On April 13, 2000, we retired, prior to maturity, $25,000,000 of our 7.5 percent First Mortgage Bonds (Bonds) due April 1, 2001. On April 25, 2000, we offered to purchase any or all of the following series of our outstanding debt: 8.95 percent Bonds due February 1, 2022; 7.33 percent Secured MTNs due April 15, 2025; 8.11 percent Secured MTNs due January 25, 2023; 7.00 percent Bonds due March 1, 2005; and 8.25 percent Bonds due February 1, 2007. The total amount outstanding for these issues was $190,000,000 as of April 25, 2000. On May 24, 2000, we retired $182,803,000 of this amount, as follows: o $44,614,000 of 7.00 percent Bonds due March 1, 2005; o $54,635,000 of 8.25 percent Bonds due February 1, 2007; o $48,554,000 of 8.95 percent Bonds due February 1, 2022; o $20,000,000 of 7.33 percent Secured Series A MTNs due April 15, 2025; and o $15,000,000 of 8.11 percent Secured Series A MTNs due January 25, 2023. We retired two additional issues of Series A Secured MTNs during 2000. On January 13, 2000, we retired $5,000,000 of 7.25 percent notes due January 19, 2024, and on June 1, 2000, we retired at maturity $20,000,000 of 7.20 percent notes. On January 14, 2000, we retired $7,000,000 of 8.68 percent Series A Unsecured MTNs due February 7, 2022. We retired $10,000,000 of 8.80 percent Series A Unsecured MTNs at maturity on February 22, 2000. All of the above debt retirements, including transaction costs, were made from the proceeds received from the 1999 sale of our electric generating assets. As discussed in Note 11, "Contingencies," we recorded long-term debt of approximately $57,000,000 regarding the Kerr mitigation in June 1997. This 26 amount represented the net present value of future costs to be paid over the life of the license. With the sale of the generating assets, payments after the sale date are no longer our responsibility. Therefore, we reduced debt on the sale date to approximately $24,300,000. On December 30, 1999, we paid approximately $14,100,000 of this amount. We included the remaining balance of $10,200,000 at December 31, 1999, in "Other" in the table above. The final payment for $10,200,000 occurred on January 3, 2000. Scheduled debt repayments on the long-term debt outstanding at December 31, 2000, amount to: $63,531,000 in 2001; $3,856,000 in 2002; $19,211,000 in 2003; $4,599,000 in 2004; zero in 2005; and $292,958,000 thereafter. On November 21, 2001, we issued $150,000,000 of 7.3 percent First Mortgage Bonds due December 1, 2006. For more information regarding our use of proceeds from the First Mortgage Bonds, see Note 17, "Nine Months Ended September 30, 2001 (Unaudited)" under the "Short-Term Borrowing" section. NOTE 9 - SHORT-TERM BORROWING We have short-term borrowing facilities with commercial banks that provide both committed and uncommitted lines of credit and the ability to sell commercial paper. Bank borrowings either bear interest at the lender's floating base rate and may be repaid at any time, or have fixed rates of interest and maturities. Commercial paper has fixed rates of interest and maturities. At December 31, 2000, we had lines of credit consisting of $85,000,000 committed and $40,000,000 uncommitted. In addition, Entech, Inc. (Entech, a wholly owned non-utility subsidiary of MPC which is not included in our combined financial statement presentation) shares with us an uncommitted credit line of $30,000,000, from which either company may borrow but the total of which they cannot exceed. Facility fees or commitment fees on the committed lines of credit are not significant. We also have the ability to issue up to $85,000,000 of commercial paper based on the total of unused committed lines of credit and revolving credit agreements. At December 31, 2000, we had outstanding notes payable to banks for $75,000,000 at a weighted average annual interest rate of 8.05 percent. Of these outstanding notes, $25,000,000 was issued from our committed lines of credit and the other $50,000,000 from our uncommitted lines of credit and the uncommitted line shared with Entech. At December 31, 1999, we had no outstanding short-term borrowing. NOTE 10 - RETIREMENT PLANS MPC maintains trusteed, noncontributory retirement plans covering substantially all of our employees. Prior to 1998, our retirement benefits were based on salary, years of service, and social security integration levels. In 1998, we amended our retirement plan's benefit provisions. Our retirement benefits are now based on salary, age, and years of service. Our plan assets consist primarily of domestic and foreign corporate stocks, domestic corporate bonds, and United States Government securities. We also have an unfunded, nonqualified benefit plan for senior management executives and directors. In December 1998, we froze the benefits earned and curtailed the plan. As a result of the sale of our electric generating assets to PPL Montana, 454 participants related to electric generation operations were curtailed from 27 the retirement plan and approximately $22,700,000 in assets were transferred from the retirement plan trust in December 1999. Pursuant to the agreement, when the calculation was finalized in February 2000, approximately $3,200,000 of additional assets were transferred to the PPL trust. In accordance with SFAS 88, we calculated a curtailment gain of approximately $4,100,000 and a settlement gain of approximately $7,800,000 in 1999. Due to regulatory accounting treatment, the gains were recorded as regulatory liabilities or offsets to regulatory assets, resulting in no income statement impact. We offered a Special Retirement Program (SRP) to certain eligible employees during 2000. The SFAS 88 special termination charge resulting from 201 utility participants electing the SRP amounted to approximately $9,814,000. Due to regulatory accounting treatment, the expense was recorded as regulatory liabilities or offsets to regulatory assets, resulting in no income statement impact. We also provide certain health care and life insurance benefits for eligible retired employees. In 1994, we established a pre-funding plan for postretirement benefits for utility employees retiring after January 1,1993. The plan assets consist primarily of domestic and foreign corporate stocks, domestic corporate bonds, and United States Government securities. The PSC allows us to include in rates all utility Other Postretirement Benefits costs on the accrual basis provided by SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." We also have a voluntary retirement savings plan in conjunction with our retirement plans. MPC contributes a matching percentage comprised of shares of MPC stock from a leveraged Employee Stock Ownership Plan arrangement and MPC shares purchased on the open market. For costs associated with these plans, see Note 6, "Other Equity." The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of plan assets over the two-year period ending December 31, 2000, and a statement of the funded status as of December 31 of both years: 28
PENSION BENEFITS OTHER BENEFITS ------------------------------------------------ 2000 1999 2000 1999 ------------------------------------------------ (Thousands of Dollars) Change in benefit obligation: Benefit obligation at January 1 $ 197,333 $ 202,666 $ 18,918 $ 20,081 Service cost on benefits earned 4,090 6,288 430 662 Interest cost on projected benefit obligation ......... 15,893 16,192 1,561 1,585 Plan amendments ............... 7,578 8,607 -- -- Assumption changes ............ 5,859 -- -- -- Actuarial (gain)/loss ......... (4,988) (23,531) 4,920 (372) Adjustments for liability transfers .................. 9,225 21,617 -- 1,963 Curtailments .................. -- (5,712) -- (3,092) Settlements ................... -- (18,096) -- -- Special termination benefits .. 9,814 -- -- -- Gross benefits paid ........... (11,694) (10,698) (2,661) (1,909) ------------------------------------------------ Benefit obligation at December 31 ................ $ 233,110 $ 197,333 $ 23,168 $ 18,918 ================================================ Change in plan assets: Fair value of plan assets at January 1 .................. $ 230,606 $ 222,484 $ 9,916 $ 7,898 Actual return/(loss) on plan assets ..................... (4,955) 16,061 329 226 Employer contributions ........ -- -- 2,122 2,817 Acquisitions/divestitures ..... (3,200) (22,707) -- -- Assets allocated (to)/from related companies .......... 11,346 23,686 -- 884 Gross benefits paid ........... (9,876) (8,918) (2,661) (1,909) ------------------------------------------------ Fair value of plan assets at December 31 ................ $ 223,921 $ 230,606 $ 9,706 $ 9,916 ================================================ Reconciliation of funded status: Funded status at end of year .. $ (9,189) $ 33,273 $ (13,461) $ (9,003) Unrecognized net: Actuarial gain ............. (23,107) (48,963) (97) (5,049) Prior service cost ......... 21,295 15,325 1,459 1,605 Transition obligation ...... (196) (245) 10,034 10,871 ------------------------------------------------ Net amount recognized at December 31 ............. $ (11,197) $ (610) $ (2,065) $ (1,576) ================================================
The following table provides the amounts recognized in the statement of financial position as of December 31:
PENSION BENEFITS OTHER BENEFITS -------------------------------------------- 2000 1999 2000 1999 -------------------------------------------- (THOUSANDS OF DOLLARS) Prepaid benefit cost ........ $ 11,028 $ 7,379 $ -- $ -- Accrued benefit cost ........ (22,225) (7,989) (2,065) (1,576) -------------------------------------------- Net amount recognized at December 31 .............. $(11,197) $ (610) $ (2,065) $ (1,576) ============================================
29 The following tables provide the components of net periodic benefit cost for the pension and other postretirement benefit plans, portions of which have been deferred or capitalized, for fiscal years 2000, 1999, and 1998:
PENSION BENEFITS -------------------------------- 2000 1999 1998 -------------------------------- (Thousands of Dollars) Service cost on benefits earned ............ $ 4,090 $ 6,288 $ 5,405 Interest cost on projected benefit obligation .............................. 15,893 16,193 13,369 Expected return on plan assets ............. (20,273) (21,767) (19,244) Amortization of: Transition obligation ................... (49) (49) (49) Prior service cost ...................... 1,607 1,522 907 Actuarial gain .......................... (2,830) (1,395) (1,259) -------------------------------- Net periodic benefit cost (credit) ......... (1,562) 792 (871) Special termination benefit charge ......... 9,814 -- -- Curtailment (gain)/loss .................... -- (3,751) -- Settlement gain ............................ -- (7,844) -- -------------------------------- Net periodic benefit cost (credit) after curtailments and settlements ...... $ 8,252 $(10,803) $ (871) ================================ OTHER BENEFITS -------------------------------- 2000 1999 1998 -------------------------------- (Thousands of Dollars) Service cost on benefits earned ............ $ 430 $ 662 $ 612 Interest cost on projected benefit obligation .............................. 1,561 1,585 1,501 Expected return on plan assets ............. (819) (723) (670) Amortization of: Transition obligation ................... 837 1,036 1,036 Prior service cost ...................... 146 158 54 Actuarial gain .......................... (128) (111) (250) -------------------------------- Net periodic benefit cost (credit) ......... 2,027 2,607 2,283 Curtailment (gain)/loss .................... -- (374) -- -------------------------------- Net periodic benefit cost (credit) after curtailments and settlements ...... $ 2,027 $ 2,233 $ 2,283 ================================
In 2000, funding for pension costs exceeded SFAS No. 87, "Employers Accounting for Pensions," pension expense by $3,078,000. In 1999, pension costs exceeded SFAS No. 87 pension expense by $1,631,000. The PSC allows recovery for the funding of pension costs through rates. Any differences between funding and expense are deferred for recognition in future periods. At December 31, 2000, the regulatory liability was $10,614,000. The following assumptions were used in the determination of actuarial present values of the projected benefit obligations:
PENSION BENEFITS OTHER BENEFITS ---------------- --------------- 2000 1999 2000 1999 ---- ----- ---- ---- Weighted average assumptions as of December 31: Discount rate ................................. 7.50% 7.75% 7.50% 7.75% Expected return on plan assets ................ 9.00% 9.00% 9.00% 9.00% Rate of compensation increase ................. 4.40% 4.40% 4.40% 4.40%
30 Assumed health care costs trend rates have a significant effect on the amounts reported for the health care plans. A change of 1 percent in assumed health care cost trend rates would have the following effects:
1% INCREASE 1% DECREASE ----------- ----------- (Thousands of Dollars) Effect on the total of service and interest cost components of net periodic post- retirement health care benefit cost ................. $ 86 $ (71) Effect on the health care component of the accumulated postretirement benefit obligation .......................................... 585 (489)
The assumed 2001 health care cost trend rates used to measure the expected cost of benefits covered by the plans is 9.00 percent. The trend rate decreases through 2007 to 5.50 percent. NOTE 11 - CONTINGENCIES |_| KERR PROJECT A FERC order that preceded our sale of the Kerr Project required us to implement a plan to mitigate the effect of the Kerr Project operations on fish, wildlife, and habitat. To implement this plan, we were required to make payments of approximately $135,000,000 between 1985 and 2020, the term during which we would have been the licensee. The net present value of the total payments, assuming a 9.5 percent annual discount rate, was approximately $57,000,000, an amount we recognized as license costs in plant and long-term debt on the Comparative Balance Sheet in 1997. In the sale of the Kerr Project, the purchaser of our electric generating assets assumed the obligation to make post-closing license compliance payments. In December 1998 and January 1999, we requested a review by the United States Court of Appeals for the District of Columbia Circuit of this order and another FERC order which included the United States Department of Interior's conditions. In December 2000, FERC issued an order approving a settlement among the parties. On February 15, 2001, the Circuit Court dismissed the petitions for review. Consequently, the approximately $24,000,000 that we paid into escrow in 2000 was released to the Confederated Salish and Kootenai Tribes (Tribes) to be used in accordance with the terms of the settlement. We have also transferred 669 acres of land on the Flathead Indian Reservation to the Tribes. With the payment and the transfer of land, we have fulfilled our obligations under the terms of this settlement. Because PPL Montana, the purchaser, assumed the obligation in excess of $24,000,000, the basis in the properties sold decreased and the regulatory liability associated with the deferred gain on the sale increased accordingly. |_| LONG-TERM POWER SUPPLY AGREEMENTS Long-term power supply agreements, primarily an agreement with a large industrial customer, exposed us to losses and potential future losses. That agreement obligated us to deliver to our customer one half of its electric energy at a fixed price and the remainder at an index-based price with a cap. When the agreement was scheduled to expire at the end of 2002, 31 the customer had an option to extend the agreement through 2004. If the customer had exercised this option, however, only index-based prices with no cap would have applied during the extension period. Until the end of 2002, we were contractually obligated to supply this and other industrial customers with electric energy purchased through an agreement indexed to the Mid-Columbia (Mid-C) market. As a result, we were exposed to the risk that electric energy we purchase at Mid-C prices could have been higher than the fixed sales rates at which we were required to sell electric energy pursuant to our power supply agreements. In June 1998, we entered into a swap with the industrial customer whose agreement exposes us to most of our risk, so that the customer could effectively purchase all of its electric energy from us at a fixed rate. At the same time, we entered into a separate fixed-price purchase and related Mid-C index sale of equivalent volumes with other counterparties to hedge that swap and eliminate our exposure to fluctuating market prices. Both the purchase and sale agreements with the other counterparties remained effective through May 2001. During the third quarter 2000, however, our industrial customer whose contract exposed us to most of the commodity price risk increased its electric energy consumption, and wholesale electric prices increased substantially. The swap and related physical offset did not extend to the increase in our customer's consumption. Specifically, the average monthly purchases of electric energy by this industrial customer increased more than 30 percent during the third quarter 2000 compared to the second quarter 2000. Average monthly wholesale electric prices in the Pacific Northwest, based on the Mid-C price index, more than doubled during the third quarter 2000 compared to the second quarter 2000. Because of these two events, the expenses of supplying our industrial customers with electric energy during the third quarter 2000 exceeded the associated revenues earned from these customers and the swap and physical offset by approximately $8,443,000. By contrast, for the entire six months ended June 30, 2000, the expenses incurred to supply these customers exceeded the associated revenues earned from these customers and the swap and physical offset by approximately $2,050,000. To mitigate future losses, we entered into a five-month agreement in October 2000 with a counterparty - a fixed-for-floating financial swap whereby we fixed our purchase price on a portion of the electric energy needed to supply our industrial customers in exchange for a Mid-C index-based price. As long as our industrial customers did not materially change their estimated electric usage, this swap allowed us to fix the total cost of supplying their electric energy during the term of the swap and, therefore, in conjunction with our existing agreements, limited our losses from supplying these customers. Based on the effects of the existing purchase and sales agreements, the financial swaps and customer usage, we incurred pretax losses of approximately $5,735,000 in the fourth quarter 2000. To eliminate our exposure to expected future losses through the remaining term of the power supply agreement, we executed a termination agreement effective June 30, 2001, under which we made a one-time payment of $62,500,000 to the industrial customer and ended our obligations under this power supply agreement. For further information on the long-term power supply agreement, see Note 17, "Nine Months Ended September 30, 2001 (Unaudited)," under "Contingencies." 32 |_| CLASS ACTION LAWSUIT On August 16, 2001, eight individuals filed a lawsuit in Montana State District Court, naming MPC, eleven of its current Board of Directors, three officers of both Touch America and MPC, and PPL Montana as defendants. In their complaint, the plaintiffs allege that MPC and its directors and officers had a legal obligation and a fiduciary duty to obtain shareholder approval before the sale of our former electric generation assets to PPL Montana. On September 14, 2001, the complaint was amended to add one other current officer of Touch America, one other current officer of MPC, and our investment banking consultants as additional defendants. As previously reported, MPC completed the sale of the electric generation assets to PPL Montana in December 1999. The plaintiffs further allege that because MPC shareholders did not vote, the sale of the generation assets is void and PPL Montana is holding these assets in constructive trust for the shareholders. Alternatively, the plaintiffs allege that MPC shareholders should have been allowed to vote on the sale of the generation assets and, if an appropriate majority vote was obtained in favor of the sale, the shareholders should have been given dissenters' rights. The plaintiffs also make various claims of breaches of duty and negligence against the Board of Directors and the individual officers. The plaintiffs have indicated that they will seek court approval to proceed with this suit as a class action. It is MPC's position that MPC and its directors and officers have fully complied with their statutory and fiduciary duties. Accordingly, MPC is defending the suit vigorously. MPC, which is seeking to have the lawsuit dismissed, filed responsive pleadings at the end of November 2001. At this early stage, however, MPC cannot predict the ultimate outcome of this matter or how it may affect our combined financial position, results of operations, or cash flows. |_| MISCELLANEOUS We are parties to various other legal claims, actions, and complaints arising in the ordinary course of business. We do not expect the conclusion of any of these matters to have a material adverse effect on our combined financial position, results of operations, or cash flows. NOTE 12 - COMMITMENTS |_| PURCHASE COMMITMENTS ELECTRIC UTILITY The Public Utilities Regulatory Policies Act (PURPA) requires a public utility to purchase power from QFs at a rate equal to what it would pay to generate or purchase power. These QFs are power production or co-generation facilities that meet size, fuel use, ownership, and operating and efficiency criteria specified by PURPA. The electric utility has 15 long-term QF contracts with expiration terms ranging from 2003 through 2032 that require us to make payments for energy capacity and energy received at prices established by the PSC. Three contracts account for 96 percent of the 101 MWs of capacity provided by these facilities. Montana's Electric Act designates the above-market portion of the QF costs as Competitive Transition Costs (CTCs) and allows for their recovery. For more information about CTCs, see Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets." 33 The Asset Purchase Agreement with PPL Montana, dated as of October 31, 1998 and amended June 29, 1999 and October 29, 1999, included two Wholesale Transition Service Agreements (WTSAs), effective December 17, 1999. These agreements enable us to fulfill our obligation to supply power until July 2002 to those customers who have not chosen another supplier. One agreement commits us to purchase 200 MWs per hour through December 2001, and the other agreement to purchase through June 2002 any power requirements remaining after having received power through the first WTSA, QFs, and Milltown Dam. Both agreements price the power sold at a market index, with a monthly floor and an annual cap. Under both agreements, the annual cap is $22.25/MWh, which has been in effect for most of 2000 because wholesale electric energy prices in the Pacific Northwest have been higher than this amount. Assuming an 8.05 percent discount rate (our average short-term borrowing rate at December 31, 2000), current market indices, and current load forecasts, we estimate the net present value of the power purchased under the WTSAs at $81,000,000 for 2001 and $34,000,000 for 2002. MPC's former subsidiary, MPT&M - which was sold on October 31, 2000 as part of the oil and natural gas businesses - had entered into several purchase power agreements in 1998. These agreements were assigned to the electric utility in 2000. One agreement obligates us to purchase 40 MWs per hour at a fixed rate until May 2001, and the other to purchase 100 MWs per hour of firm capacity and firm energy at 100 percent load factor at a market-indexed rate until August 2001. NATURAL GAS UTILITY The natural gas utility entered into take-or-pay contracts with Montana natural gas producers to provide adequate supplies of natural gas for our utility customers. We currently have six of these contracts, with expirations between 2002 and 2006. If we can supply customers with less expensive natural gas, we purchase the minimum required by the take-or-pay contracts. The cost of purchases through take-or-pay contracts is part of those costs submitted to the PSC for recovery in future rates. Since 1998, the natural gas utility enters only into one-year take-or-pay contracts, because of the uncertainty about the number and timing of customers who will choose another natural gas supplier under Montana's Natural Gas Act. CONTRACTUAL PAYMENTS AND PRESENT VALUE Total payments under all of these contracts for the prior three years were as follows:
UTILITY TOTAL ----------------------------------- ELECTRIC NATURAL GAS ----------------------------------- (Thousands of Dollars) 2000 $272,075 $ 7,101 $279,176 1999 61,274 4,069 65,343 1998 50,611 3,508 54,119
34 Under the above agreements, the present value of future minimum payments, at a discount rate of 8.05 percent, is as follows:
UTILITY TOTAL ------------------------------------------ ELECTRIC NATURAL GAS ------------------------------------------ (Thousands of Dollars) 2001 $224,435 $ 5,003 $229,438 2002 42,905 4,450 47,355 2003 8,380 641 9,021 2004 8,001 546 8,547 2005 7,537 465 8,002 Remainder 97,486 395 97,881 ------------------------------------------ $388,744 $ 11,500 $400,244 ==========================================
|_| LEASE COMMITMENTS On December 30, 1985, we sold our 30-percent share of Colstrip Unit 4 agreed to lease back our share under a net, 25-year lease with annual payments of approximately $32,000,000. We have been accounting for this transaction as an operating lease. We did not sell this nonutility leasehold interest and its related assets and liabilities and contract obligations to PPL Montana in 1999. This lease is included in the anticipated sale of the Utility to NorthWestern Corporation. We have no other material minimum operating lease payments. Capitalized leases are not material and are included in other long-term debt. Rental expense for the prior three years, including Colstrip Unit 4, was $41,900,000 for 2000, $59,300,000 for 1999, and $58,800,000 for 1998. NOTE 13 - NEW ACCOUNTING PRONOUNCEMENTS |_| SFAS NOS. 141, 142, 143, AND 144 In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations." SFAS No. 141 eliminates the use of the pooling of interests method of accounting, and requires that all mergers and acquisitions be accounted for using the purchase method of accounting. SFAS No. 141 also establishes specific criteria for the recognition of intangible assets separately from goodwill and adds new disclosure requirements. This statement is effective for all mergers and acquisitions initiated after June 30, 2001. Adoption of this pronouncement is not expected to have a material impact on our financial position, results of operations, or cash flows. In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangibles." SFAS No. 142 eliminates amortization of goodwill and other indefinite-lived intangibles. These assets will now be assessed at least annually for impairment using a fair value based test. Intangible assets with a finite life will continue to be amortized over that life. The amortization provisions of SFAS No. 142 apply to goodwill and other intangibles acquired after June 30, 2001. For goodwill and other intangible assets acquired prior to July 1, 2001, adoption of SFAS No. 142 is required for fiscal years beginning after December 15, 2001. We are currently evaluating this pronouncement, but we do not expect it to have a material impact on our financial position, results of operations, or cash flows. 35 In June 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a legal liability for an asset retirement obligation in the period it is incurred. The asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. We are currently evaluating this pronouncement, but we do not expect it to have a material impact on our financial position, results of operations, or cash flows. In August 2001, the FASB issued SFAS No. 144 "Accounting for the Impairment of Long-Lived Assets." SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This statement is effective for financial statements issued for fiscal years beginning after December 15, 2001. We are currently evaluating the impact, if any, this pronouncement will have on our financial position, results of operations, or cash flows. 36 NOTE 14 - INFORMATION ON INDUSTRY SEGMENTS Our utility business purchases, transmits, and distributes electric energy and natural gas, and the Colstrip Unit 4 division manages long-term power supply agreements. Our other operations consists primarily of Montana Power Services Company, One Call Locators, LLC, and Discovery Energy Solutions, Inc. (DES). One Call Locators, LLC, locates underground lines while DES handles the energy productivity improvement activities. Identifiable assets of each industry segment are principally those assets used in our operation of those industry segments. Corporate assets are principally cash and cash equivalents and temporary investments. We consider segment information for foreign operations to be insignificant. 37 NOTE 14 - INFORMATION ON INDUSTRY SEGMENTS (CONT.) OPERATIONS INFORMATION
NINE MONTHS ENDED ----------------------------------------- SEPTEMBER 30, 2001 ----------------------------------------- (Thousands of Dollars) INDUSTRY SEGMENTS ELECTRIC NATURAL GAS OTHER ----------------------------------------- Sales to unaffiliated customers .................. $ 421,850 $ 100,365 $ 14,091 Intersegment sales ............................... 542 234 1,066 Pretax operating income (loss) ................... (34,759) (1,786) 1,753 Capital expenditures ............................. 29,220 15,127 449 Identifiable assets .............................. 1,033,089 522,553 34,311 RECONCILIATION TO COMBINED TOTAL SEGMENT COMBINED TOTAL ADJUSTMENTS(a) TOTAL ----------------------------------------- Sales to unaffiliated customers .................. $ 536,306 $ -- $ 536,306 Intersegment sales ............................... 1,842 (1,842) -- Pretax operating loss ............................ (34,792) -- (34,792) Capital expenditures ............................. 44,796 -- 44,796 Identifiable assets .............................. 1,589,953 -- 1,589,953
YEAR ENDED ----------------------------------------- DECEMBER 31, 2000 ----------------------------------------- (Thousands of Dollars) INDUSTRY SEGMENTS ELECTRIC NATURAL GAS OTHER ----------------------------------------- Sales to unaffiliated customers .................. $ 535,654 $ 129,220 $ 11,179 Intersegment sales ............................... 772 269 1,291 Depreciation and amortization .................... 39,559 8,830 5,734 Pretax operating income (loss) ................... 18,168 (4,405) 334 Interest expense ................................. 26,726 16,077 1,047 Interest income .................................. 12,041 4,984 -- Income tax benefit ............................... (9,399) (9,943) (257) Capital expenditures ............................. 42,718 7,546 27,603 Identifiable assets .............................. 1,244,530 363,870 76,385 RECONCILIATION TO COMBINED TOTAL SEGMENT COMBINED TOTAL ADJUSTMENTS(a) TOTAL ----------------------------------------- Sales to unaffiliated customers .................. $ 676,053 $ -- $ 676,053 Intersegment sales ............................... 2,332 (2,332) -- Depreciation and amortization .................... 54,123 -- 54,123 Pretax operating income .......................... 14,097 -- 14,097 Interest expense ................................. 43,850 (2,478) 41,372 Interest income .................................. 17,025 (2,478) 14,547 Income tax benefit ............................... (19,599) -- (19,599) Capital expenditures ............................. 77,867 -- 77,867 Identifiable assets .............................. 1,684,785 -- 1,684,785
(a) The amounts indicated include certain eliminations between the business segments. 38 NOTE 14 - INFORMATION ON INDUSTRY SEGMENTS (CONT.) OPERATIONS INFORMATION
YEAR ENDED ----------------------------------------- DECEMBER 31, 1999 ----------------------------------------- (Thousands of Dollars) INDUSTRY SEGMENTS ELECTRIC NATURAL GAS OTHER ----------------------------------------- Sales to unaffiliated customers .................. $ 545,390 $ 111,417 $ 274 Intersegment sales ............................... 714 202 889 Depreciation and amortization .................... 56,282 9,275 4,137 Pretax operating income .......................... 113,740 16,430 2,055 Interest expense ................................. 37,893 15,229 706 Interest income .................................. 3,875 793 (9) Income tax expense ............................... 13,054 380 461 Capital expenditures ............................. 50,503 13,115 15,957 Identifiable assets .............................. 1,687,511 495,846 40,987 RECONCILIATION TO COMBINED TOTAL SEGMENT COMBINED TOTAL ADJUSTMENTS(a) TOTAL ----------------------------------------- Sales to unaffiliated customers .................. $ 657,081 $ -- $ 657,081 Intersegment sales ............................... 1,805 (1,805) -- Depreciation and amortization .................... 69,694 -- 69,694 Pretax operating income .......................... 132,225 -- 132,225 Interest expense ................................. 53,828 (973) 52,855 Interest income .................................. 4,659 (973) 3,686 Income tax expense ............................... 13,895 -- 13,895 Capital expenditures ............................. 79,575 -- 79,575 Identifiable assets .............................. 2,224,344 -- 2,224,344
YEAR ENDED ----------------------------------------- DECEMBER 31, 1998 ----------------------------------------- (Thousands of Dollars) INDUSTRY SEGMENTS ELECTRIC NATURAL GAS OTHER ----------------------------------------- Sales to unaffiliated customers .................. $ 530,400 $ 107,363 $ -- Intersegment sales ............................... 850 192 -- Depreciation and amortization .................... 59,213 8,683 3,684 Pretax operating income (loss) ................... 127,710 14,977 (18) Interest expense ................................. 48,098 12,947 961 Interest income .................................. 3,330 439 -- Income tax expense (benefit) ..................... 27,760 134 (467) Capital expenditures ............................. 69,080 25,193 188 Identifiable assets .............................. 1,664,568 588,291 30,246 RECONCILIATION TO COMBINED TOTAL SEGMENT COMBINED TOTAL ADJUSTMENTS(a) TOTAL ----------------------------------------- Sales to unaffiliated customers .................. $ 637,763 $ -- $ 637,763 Intersegment sales ............................... 1,042 (1,042) -- Depreciation and amortization .................... 71,580 -- 71,580 Pretax operating income .......................... 142,669 -- 142,669 Interest expense ................................. 62,006 (1,004) 61,002 Interest income .................................. 3,769 (1,004) 2,765 Income tax expense ............................... 27,427 -- 27,427 Capital expenditures ............................. 94,461 -- 94,461 Identifiable assets .............................. 2,283,105 -- 2,283,105
(a) The amounts indicated include certain eliminations between the business segments. 39 NOTE 15 - OTHER INCOME - NET The following table provides the components of other income - net:
UNAUDITED NINE MONTHS YEAR ENDED DECEMBER 31, ENDED ------------------------------------ 9/30/01 2000 1999 1998 ----------------------------------------------------- Interest income ........ $ (2,496) $(14,547) $ (3,686) $ (2,765) Other .................. 789 66 1,119 195 ----------------------------------------------------- $ (1,707) $(14,481) $ (2,567) $ (2,570) =====================================================
NOTE 16 - GENERATION ASSETS (UNAUDITED) As discussed in Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets," on December 17, 1999, MPC sold substantially all of our electric generating assets and related contracts. Prior to the sale, the combined statements of income for the years ended December 31, 1999 and 1998 include generation amounts. These amounts consist of the following:
YEAR ENDED ------------------------ DECEMBER 31, ------------------------ 1999 1998 ------------------------ (Thousands of Dollars) REVENUES* ........................................ $ 228,811 $ 240,144 EXPENSES: Operations and maintenance .................... 147,451 142,636 Selling, general, and administrative .......... 9,021 13,469 Taxes other than income taxes ................. 17,306 15,770 Depreciation and amortization ................. 19,378 19,728 ------------------------ 193,156 191,603 INCOME FROM OPERATIONS ........................... 35,655 48,541 INTEREST EXPENSE AND OTHER INCOME: Interest ...................................... 7,443 19,207 Other income - net ............................ (883) (714) ------------------------ 6,560 18,493 ------------------------ INCOME BEFORE INCOME TAXES .................... 29,095 30,048 INCOME TAX EXPENSE (BENEFIT) ..................... (7,490) 8,115 ------------------------ NET INCOME ....................................... $ 36,585 $ 21,933 ========================
* Generation revenues include an allocation of our previously bundled rates. NOTE 17 - NINE MONTHS ENDED SEPTEMBER 30, 2001 (UNAUDITED) |_| DERIVATIVE FINANCIAL INSTRUMENTS For the month of July 2001, we entered into a swap agreement with a counterparty to hedge 50 MWs, which we were purchasing at the Mid-C 40 index price from a power generator, but were selling at a fixed price to a power marketer. The hedged electric energy sales resulted in a $200,000 after-tax gain and the ineffective swap hedging those sales in a $400,000 after-tax loss. It was our only derivative transaction in the third quarter 2001. For the nine months ended September 30, 2001, the hedged electric energy sales resulted in an after-tax loss of $25,300,000, and the price swaps hedging those sales in an after-tax gain of approximately $7,200,000. At September 30, 2001, we did not have agreements to purchase electric energy for sales to power marketers and, therefore, do not expect to enter into financial derivative transactions in the fourth quarter 2001. |_| LONG-TERM DEBT We made scheduled semi-annual repayments of approximately $2,500,000 and $1,700,000 on our 6.2 percent natural gas transition bonds on March 15, 2001 and September 17, 2001, respectively. In addition, on April 6, 2001, we retired $60,000,000 of our variable rate Series B Unsecured Medium Term Notes at maturity. |_| SHORT-TERM BORROWING At September 30, 2001, we had committed lines of credit of $65,000,000, uncommitted lines of $30,000,000, and outstanding notes payable to banks for $74,600,000. These notes consisted of $60,000,000 from our committed lines of credit and $14,600,000 from our uncommitted lines, at a weighted average annual interest rate of 4.36 percent. Facility or commitment fees on the committed lines of credit are not significant. Our committed and uncommitted lines expired by the end of November 2001. On November 21, 2001, we issued $150,000,000 in First Mortgage Bonds. We have used the proceeds from the bonds to repay the $60,000,000 outstanding under our committed credit line, repay $15,800,000 in short-term borrowings, and repay an intercompany loan between Montana Power and Entech. We expect to use the remaining balance for existing cash requirements and to redeem our ESOP Notes. |_| CONTINGENCIES LONG-TERM POWER SUPPLY AGREEMENTS Long-term power supply agreements, primarily an agreement with a large industrial customer, had exposed us to losses and potential future losses mainly because of unusually high electric energy market prices. To eliminate our exposure to expected future losses through December 2002 when the agreement with that customer terminated, we executed a termination agreement effective June 30, 2001. Under the termination agreement, we made a one-time payment of $62,500,000 to the customer and ended our obligations under this power supply agreement. We recorded a pretax loss of $62,500,000, or approximately $37,900,000 after income taxes, in the second quarter 2001. Prior to the termination agreement, we recorded pretax losses associated with the power supply agreement of approximately $2,500,000 in the first quarter 2001 and $22,500,000 in the second quarter 2001. |_| COMMITMENTS ELECTRIC UTILITY In its 2001 session, the Montana Legislature passed House Bill 474, which extends the transition period of electric deregulation in Montana from July 1, 2002 to July 1, 2007 and, therefore, our obligation as a default supplier through June 30, 2007. We entered into three purchase power agreements in 41 October 2001 that enable us to satisfy, in part, our electric default supply obligation. These agreements commit us to purchase a total of 561 MWs per hour during peak hours and 411 MWs per hour during off-peak hours in the first year of the extended transition period. In the remaining four years of the transition period, the agreements also obligate us to purchase 450 MWs per hour during the peak hours and 300 MWs per hour during the off-peak hours. These purchases are included in our default supply portfolio filing with the PSC dated October 29, 2001. Assuming a 4.36 percent discount rate and current load forecast, the present value of future minimum payments under these agreements is as follows:
Thousands of Dollars ------------ 2002.................. $ 62,186 2003.................. 107,691 2004.................. 92,452 2005.................. 88,337 2006.................. 84,649 Remainder............. 40,558 ------------ $ 475,873 ============
House Bill 474 also provides for the complete recovery in rates of the default supplier's costs that are prudently incurred to supply electric energy. 42 EX-99.2 4 a2065702zex-99_2.txt EXHIBIT 99.2 Exhibit 99.2 UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION The following presents our unaudited pro forma combined financial information as of September 30, 2001 and for the year ended December 31, 2000 and for the nine months ended September 30, 2001. The unaudited pro forma combined statements of income for the year ended December 31, 2000 and the nine months ended September 30, 2001 give effect to the following transactions as if each transaction had occurred as of the beginning of the period presented and the unaudited pro forma combined balance sheet as of September 30, 2001 gives effect to the following transactions as if each transaction had occurred on September 30, 2001: - the sale of 3,680,000 shares of our common stock issued in October 2001 at $21.25 per share and the use of the net proceeds therefrom; - the proposed sale of 8,000,000 shares of trust preferred securities, assuming an offering of $200 million aggregate amount of securities and assuming a dividend rate of 8% thereon and the use of the net proceeds therefrom; - our pending acquisition of the utility business of Montana Power (the "MPC Utility"), which includes regulated electric and natural gas distribution and transmission operations and certain unregulated, energy-related businesses that provide products and services to industrial, institutional and commercial customers, for a purchase price of $1.1 billion, including the assumption of approximately $488 million in existing debt and preferred stock of The Montana Power Company ("Montana Power"); and - our anticipated initial financing of the acquisition of the MPC Utility, assuming the equity purchase price is fully funded via an acquisition facility and assuming interest rates on such facility as of December 6, 2001. The unaudited pro forma combined financial information is based upon currently available information and assumptions that our management believes are reasonable. The unaudited pro forma combined financial information is prepared for illustrative purposes only and is not necessarily indicative of the operating results or financial condition of the company that would have occurred had the transactions occurred at the periods presented, nor is the unaudited pro forma combined financial information necessarily indicative of future operating results or the financial position of the combined companies. Pro forma results for the nine months ended September 30, 2001 are not necessarily indicative of the results that may be expected for a full year. You should read the following tables in conjunction with "Montana Power Company Utility Unaudited Pro Forma Combined Condensed Financial Data" included in Exhibit 99.3 hereto, the consolidated financial statements and notes thereto of NorthWestern and the combined financial statements and notes thereto of the Utility of The Montana Power Company included in Exhibit 99.1 hereto. S-58 NORTHWESTERN CORPORATION UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME (in thousands, except for per share amounts)
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001 ----------------------------------------------- TRUST PREFERRED NORTHWESTERN COMMON STOCK SECURITIES CORPORATION OFFERING OFFERING ACTUAL ADJUSTMENT(1) ADJUSTMENT(2) ------------ -------------- --------------- OPERATING REVENUES........... $3,440,336 COST OF SALES................ 2,784,079 ----------- GROSS MARGIN................. 656,257 ----------- OPERATING EXPENSES: Selling, general and administrative expenses................. 607,596 Depreciation and amortization............. 91,300 ----------- 698,896 ----------- OPERATING INCOME (LOSS)...... (42,639) Interest expense............. (66,253) $1,325 $6,249 Investment income and other...................... 4,130 ----------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS.................. (104,762) 1,325 6,249 Benefit (provision) for income taxes............... 17,247 (517) 2,243 ----------- ---------- ---------- INCOME (LOSS) BEFORE MINORITY INTERESTS.................. (87,515) 808 8,492 Minority interests........... 126,956 ----------- ---------- ---------- NET INCOME................... 39,441 808 8,492 Minority interest on preferred securities of subsidiary trust........... (4,950) (12,000) Dividends on cumulative preferred stock............ (144) ----------- ---------- ---------- EARNINGS ON COMMON STOCK..... $34,347 $808 $(3,508) =========== ========== ========== AVERAGE COMMON SHARES OUTSTANDING................ 23,604 3,680 EARNINGS PER AVERAGE COMMON SHARE Basic...................... $1.46 Diluted.................... 1.45 FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001 ----------------------------------------------------------- NORTHWESTERN NORTHWESTERN PRO FORMA AS PRO FORMA AS ADJUSTED FOR NORTHWESTERN FURTHER COMMON STOCK INITIAL MPC ADJUSTED FOR AND TRUST UTILITY MPC UTILITY PREFERRED PRO FORMA ACQUISITION ACQUISITION SECURITIES MPC UTILITY FINANCING AND OFFERINGS ADJUSTMENT(3) ADJUSTMENT(4) FINANCING ------------ ------------- ------------- ------------ OPERATING REVENUES........... $3,440,336 $490,651 $3,930,987 COST OF SALES................ 2,784,079 248,172 3,032,251 ----------- ---------- ----------- GROSS MARGIN................. 656,257 242,479 898,736 ----------- ---------- ----------- OPERATING EXPENSES: Selling, general and administrative expenses................. 607,596 124,617 732,213 Depreciation and amortization............. 91,300 42,765 134,065 ----------- ---------- ----------- 698,896 167,382 866,278 ----------- ---------- ----------- OPERATING INCOME (LOSS)...... (42,639) 75,097 32,458 Interest expense............. (58,679) (24,721) $(21,446) (104,846) Investment income and other...................... 4,130 1,707 5,837 ----------- ---------- ---------- ----------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS.................. (97,188) 52,083 (21,446) (66,551) Benefit (provision) for income taxes............... 18,973 (18,706) 8,364 8,631 ----------- ---------- ---------- ----------- INCOME (LOSS) BEFORE MINORITY INTERESTS.................. (78,215) 33,377 (13,082) (57,920) Minority interests........... 126,956 126,956 ----------- ---------- ---------- ----------- NET INCOME................... 48,741 33,377 (13,082) 69,036 Minority interest on preferred securities of subsidiary trust........... (16,950) (4,119) (21,069) Dividends on cumulative preferred stock............ (144) (144) ----------- ---------- ---------- ----------- EARNINGS ON COMMON STOCK..... $31,647 $29,258 $(13,082) $47,823 =========== ========== ========== =========== AVERAGE COMMON SHARES OUTSTANDING................ 27,284 27,284 EARNINGS PER AVERAGE COMMON SHARE Basic...................... $1.16 $1.75 Diluted.................... 1.16 1.75
The accompanying notes are an integral part of these pro forma combined financial statements S-59 NORTHWESTERN CORPORATION UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME (in thousands, except for per share amounts)
FOR THE YEAR ENDED DECEMBER 31, 2000 ---------------------------------------------------------------- NORTHWESTERN PRO FORMA AS ADJUSTED FOR COMMON STOCK TRUST PREFERRED AND NORTHWESTERN COMMON STOCK SECURITIES TRUST PREFERRED CORPORATION OFFERING OFFERING SECURITIES ACTUAL ADJUSTMENT(1) ADJUSTMENT(2) OFFERINGS ------------ ------------- --------------- --------------- OPERATING REVENUES............ $7,132,090 $7,132,090 COST OF SALES................. 6,295,675 6,295,675 ----------- ----------- GROSS MARGIN.................. 836,415 836,415 ----------- ----------- OPERATING EXPENSES: Selling, general and administrative expenses... 686,814 686,814 Depreciation and amortization.............. 108,329 108,329 ----------- ----------- 795,143 795,143 ----------- ----------- OPERATING INCOME (LOSS)....... 41,272 41,272 Interest expense.............. (77,207) $2,986 $14,244 (59,977) Investment income and other... 8,981 8,981 ----------- ----------- ----------- ----------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS................... (26,954) 2,986 14,244 (9,724) Benefit (provision) for income taxes....................... 4,117 (1,165) 685 3,637 ----------- ----------- ----------- ----------- INCOME (LOSS) BEFORE MINORITY INTERESTS................... (22,837) 1,821 14,929 (6,087) Minority interests............ 73,436 73,436 ----------- ----------- ----------- ----------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE........ 50,599 1,821 14,929 67,349 Cumulative effect on change in accounting principle, net of tax and minority interests................... (1,046) (1,046) ----------- ----------- ----------- ----------- NET INCOME.................... 49,553 1,821 14,929 66,303 Minority Interest on Preferred Securities of Subsidiary Trust....................... (6,601) (16,000) (22,601) Dividends on Cumulative Preferred Stock............. (191) (191) ----------- ----------- ----------- ----------- EARNINGS ON COMMON STOCK...... $42,761 $1,821 $(1,071) $43,511 =========== =========== =========== =========== AVERAGE COMMON SHARES OUTSTANDING................. 23,141 3,680 26,821 EARNINGS PER AVERAGE COMMON SHARE Basic before cumulative effect...................... $1.89 $1.66 Cumulative effect of change in accounting principle... (0.04) (0.04) Basic....................... 1.85 1.62 Diluted before cumulative effect.................... 1.87 1.64 Cumulative effect of change in accounting principle... (0.04) (0.04) Diluted..................... 1.83 1.60 FOR THE YEAR ENDED DECEMBER 31, 2000 -------------------------------------------- NORTHWESTERN PRO FORMA NORTHWESTERN AS FURTHER INITIAL MPC ADJUSTED FOR PRO FORMA UTILITY MPC UTILITY MPC ACQUISITION ACQUISITION UTILITY FINANCING AND ADJUSTMENT(3) ADJUSTMENT(4) FINANCING ------------- ------------- ------------ OPERATING REVENUES............ $628,144 $7,760,234 COST OF SALES................. 319,505 6,615,180 ---------- ----------- GROSS MARGIN.................. 308,639 1,145,054 ---------- ----------- OPERATING EXPENSES: Selling, general and administrative expenses... 186,183 872,997 Depreciation and amortization.............. 54,123 162,452 ---------- ----------- 240,306 1,035,449 ---------- ----------- OPERATING INCOME (LOSS)....... 68,333 109,605 Interest expense.............. (35,880) $(28,595) (124,452) Investment income and other... 14,481 23,462 ---------- ---------- ----------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS................... 46,934 (28,595) 8,615 Benefit (provision) for income taxes....................... (16,162) 11,152 (1,373) ---------- ---------- ----------- INCOME (LOSS) BEFORE MINORITY INTERESTS................... 30,772 (17,443) 7,242 Minority interests............ 73,436 ---------- ---------- ----------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE........ 30,772 (17,443) 80,678 Cumulative effect on change in accounting principle, net of tax and minority interests................... (1,046) ---------- ---------- ----------- NET INCOME.................... 30,772 (17,443) 79,632 Minority Interest on Preferred Securities of Subsidiary Trust....................... (5,492) (28,093) Dividends on Cumulative Preferred Stock............. (191) ---------- ---------- ----------- EARNINGS ON COMMON STOCK...... $25,280 $(17,443) $51,348 ========== ========== =========== AVERAGE COMMON SHARES OUTSTANDING................. 26,821 EARNINGS PER AVERAGE COMMON SHARE Basic before cumulative effect...................... $1.95 Cumulative effect of change in accounting principle... (0.04) Basic....................... 1.91 Diluted before cumulative effect.................... 1.93 Cumulative effect of change in accounting principle... (0.04) Diluted..................... 1.89
The accompanying notes are an integral part of these pro forma combined financial statements S-60 NORTHWESTERN CORPORATION UNAUDITED PRO FORMA COMBINED BALANCE SHEET (in thousands)
AT SEPTEMBER 30, 2001 ---------------------------------------------------------------------------------- NORTHWESTERN PRO FORMA AS ADJUSTED FOR COMMON STOCK TRUST PREFERRED AND NORTHWESTERN COMMON STOCK SECURITIES TRUST PREFERRED PRO FORMA CORPORATION OFFERING OFFERING SECURITIES MPC UTILITY ACTUAL ADJUSTMENT(5) ADJUSTMENT(6) OFFERINGS ADJUSTMENT(7) ------------ --------------- --------------- --------------- ------------- ASSETS CURRENT ASSETS: Cash and cash equivalents... $84,496 $30,072 $114,568 $6,504 Accounts receivable, net.... 388,243 388,243 54,439 Inventories................. 89,290 89,290 11,508 Other....................... 83,556 83,556 106,381 ----------- ------------ ------------- ----------- 645,585 30,072 675,657 178,832 ----------- ------------ ------------- ----------- PROPERTY, PLANT AND EQUIPMENT, NET......................... 806,236 806,236 1,092,178 GOODWILL AND OTHER INTANGIBLE ASSETS, NET................. 994,721 994,721 7,561 OTHER ASSETS: Investments................. 96,733 96,733 25,439 Other assets................ 80,009 $6,800 86,809 226,471 ----------- ------------ ------------- ----------- 176,742 6,800 183,542 251,910 ----------- ------------ ------------ ------------- ----------- $2,623,284 $30,072 $6,800 $2,660,156 $1,530,481 =========== ============ ============ ============= =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long- term debt................. $5,000 $5,000 $3,399 Current maturities of long- term debt--nonrecourse.... 106,522 106,522 Short-term debt............. 8,000 $(8,000) Short-term debt of subsidiaries--nonrecourse... 167,723 167,723 Accounts payable............ 269,002 269,002 37,162 Accrued expenses............ 226,195 226,195 133,556 ----------- ------------ ------------- ----------- 782,442 (8,000) 774,442 174,117 ----------- ------------ ------------- ----------- LONG-TERM LIABILITIES: Long-term debt.............. 586,350 (1,800) $(193,200) 391,350 419,601 Long-term debt of subsidiaries--nonrecourse... 491,765 491,765 Deferred income taxes....... 46,663 46,663 Other noncurrent liabilities............... 58,469 58,469 380,947 ----------- ------------ ------------ ------------- ----------- 1,183,247 (1,800) (193,200) 988,247 800,548 ----------- ------------ ------------ ------------- ----------- MINORITY INTERESTS............ 234,552 (35,000) 199,552 PREFERRED STOCK, PREFERENCE STOCK AND PREFERRED SECURITIES: Preferred stock--4 1/2% series.................... 2,600 2,600 Redeemable preferred stock-- 6 1/2% series............. 1,150 1,150 Preference stock............ Company obligated manditorily redeemable security of trust holding solely parent debentures................ 87,500 200,000 287,500 65,000 ----------- ------------ ------------- ----------- 91,250 200,000 291,250 65,000 ----------- ------------ ------------- ----------- SHAREHOLDERS' EQUITY: Common stock................ 41,502 6,440 47,942 Paid-in capital............. 172,954 68,432 241,386 490,816 Retained earnings........... 117,838 117,838 Accumulated other comprehensive income...... (501) (501) ----------- ------------ ------------- ----------- 331,793 74,872 406,665 490,816 ----------- ------------ ------------ ------------- ----------- $2,623,284 $30,072 $6,800 $2,660,156 $1,530,481 =========== ============ ============ ============= =========== AT SEPTEMBER 30, 2001 ------------------------------- NORTHWESTERN NORTHWESTERN PRO FORMA AS INITIAL MPC FURTHER UTILITY ADJUSTED FOR ACQUISITION MPC UTILITY FINANCING ACQUISITION ADJUSTMENT(8) AND FINANCING -------------- -------------- ASSETS CURRENT ASSETS: Cash and cash equivalents... $121,072 Accounts receivable, net.... 442,682 Inventories................. 100,798 Other....................... 189,937 ------------ 854,489 ------------ PROPERTY, PLANT AND EQUIPMENT, NET......................... 1,898,414 GOODWILL AND OTHER INTANGIBLE ASSETS, NET................. $111,184 1,113,466 OTHER ASSETS: Investments................. 122,172 Other assets................ 313,280 ------------ ------------ 435,452 ------------ ------------ $111,184 $4,301,821 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long- term debt................. $8,399 Current maturities of long- term debt--nonrecourse.... 106,522 Short-term debt............. -- Short-term debt of subsidiaries--nonrecourse... 167,723 Accounts payable............ 306,164 Accrued expenses............ 359,751 ------------ 948,559 ------------ LONG-TERM LIABILITIES: Long-term debt.............. $602,000 1,412,951 Long-term debt of subsidiaries--nonrecourse... 491,765 Deferred income taxes....... 46,663 Other noncurrent liabilities............... 439,416 ------------ ------------ 602,000 2,390,795 ------------ ------------ MINORITY INTERESTS............ 199,552 PREFERRED STOCK, PREFERENCE STOCK AND PREFERRED SECURITIES: Preferred stock--4 1/2% series.................... 2,600 Redeemable preferred stock-- 6 1/2% series............. 1,150 Preference stock............ Company obligated manditorily redeemable security of trust holding solely parent debentures................ 352,500 ------------ 356,250 ------------ SHAREHOLDERS' EQUITY: Common stock................ 47,942 Paid-in capital............. (490,816) 241,386 Retained earnings........... 117,838 Accumulated other comprehensive income...... (501) ------------ ------------ (490,816) 406,665 ------------ ------------ $111,184 $4,301,821 ============ ============
The accompanying notes are an integral part of these pro forma combined financial statements. S-61 NORTHWESTERN CORPORATION NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION The Unaudited Pro Forma Combined Financial Information is based on the following assumptions: (1) Reflects the receipt of $74.9 million net proceeds, after deducting offering expenses, from the sale of 3,680,000 shares of common stock issued in October 2001 at $21.25 per share and the application of the proceeds therefrom. Approximately $35.0 million of these net proceeds were contributed to NorthWestern's Blue Dot Services, Inc. subsidiary for the redemption of certain preferred stock and common stock pursuant to existing agreements, and the remainder was used for general corporate purposes, including reducing short-term debt and amounts drawn under NorthWestern's existing credit facility. (2) Reflects the receipt of $193.2 million of net proceeds, after paying the underwriting commission and the estimated offering expenses of approximately $500,000, from the proposed sale of NorthWestern's trust preferred securities, assuming an offering of 8,000,000 trust preferred securities and assuming a dividend rate of 8% and the use of proceeds from the sale for general corporate purposes and to repay a portion of the amounts outstanding under NorthWestern's existing credit facility. A change of 1/8% in interest rates on the trust preferred securities would increase or decrease pre-tax interest expense by $250,000 per annum. (3) Reflects the results of operations of the MPC Utility for a purchase price of $1.1 billion, including the assumption of approximately $488 million in existing Montana Power debt and preferred stock. (4) Reflects NorthWestern's anticipated initial financing of the acquisition of the MPC Utility. The initial financing assumes the equity purchase price is fully funded via an acquisition facility and assuming interest rates on such acquisition facility as of December 6, 2001. We currently intend to issue a combination of long term debt and equity following the closing of the acquisition of the MPC Utility to refinance the initial financing and provide working capital. A change of 1/8% in interest rates would increase or decrease pre-tax interest expense by $753,000 per annum. (5) Reflects the receipt of $74.9 million of net proceeds, after deducting offering expenses, from the sale of 3,680,000 shares of common stock issued in October 2001 at $21.25 per share and the application of the proceeds therefrom. Approximately $35.0 million of these net proceeds were contributed to NorthWestern's Blue Dot Services, Inc. subsidiary for the redemption of certain preferred stock and common stock pursuant to existing agreements, and the remainder was used for general corporate purposes, including reducing short-term debt and amounts drawn under NorthWestern's existing credit facility. (6) Reflects the receipt of $193.2 million of net proceeds, after paying the underwriting commission and the estimated offering expenses of approximately $500,000, from the proposed sale of NorthWestern's trust preferred securities, assuming an offering of $200 million aggregate amount of trust preferred securities and the use of proceeds from the sale for general corporate purposes and to repay a portion of the amounts outstanding under NorthWestern's existing credit facility. (7) Reflects the balances of the MPC Utility. Purchase adjustments have been made to the assets and liabilities of the MPC Utility to reflect the effect of the pending acquisition accounted for under the purchase method of accounting. Certain pro forma adjustments are based, in part, on the impact of the terms and conditions of the Unit Purchase Agreement governing our acquisition of the MPC Utility and we cannot assure you that such terms and conditions will remain unchanged. Pro forma adjustments exclude certain cash accounts representing excess proceeds from the MPC Utility's previous sale of generation assets, which cash will be applied to reduce transition and stranded costs under the jurisdiction of the MPSC and FERC. (8) Reflects NorthWestern's anticipated initial financing of the acquisition of the MPC Utility. We currently intend to issue a combination of long term debt and equity following the closing of the acquisition of the MPC Utility to refinance the acquisition term loan and provide working capital. Goodwill will be recognized, representing the portion of the purchase price in excess of the fair value of identified assets and liabilities. No amortization of goodwill is included in the Unaudited Pro Forma Combined Financial Information, as provided in Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," for business combinations completed after June 30, 2001. The allocation of the purchase price will be based on the fair value of identified assets and liabilities as of the date the business combination is completed. Accordingly, goodwill will be adjusted as a result of the determination of such fair value and thus will differ from the amount reported in the Unaudited Pro Forma Combined Condensed Balance Sheet. While we believe the historical assets and liabilities approximate fair value, if we identify any intangible assets separate from goodwill, they will be subject to amortization. S-62 EX-99.3 5 a2065702zex-99_3.txt EXHIBIT 99.2 Exhibit 99.3 MONTANA POWER COMPANY UTILITY UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL DATA The following presents unaudited pro forma combined financial data for the utility business of The Montana Power Company ("Montana Power"), which includes regulated electric and natural gas distribution and transmission operations and certain unregulated, energy-related businesses that provide products and services to industrial, institutional and commercial customers ("The Utility of The Montana Power Company") as of September 30, 2001 and for the year ended December 31, 2000 and for the nine months ended September 30, 2001 to reflect the portion of The Utility of The Montana Power Company that NorthWestern Corportion ("NorthWestern") has agreed to purchase pursuant to a Unit Purchase Agreement, dated as of October 29, 2000, as amended (such portion of The Utility of The Montana Power Company, the "MPC Utility"). The pro forma statements of income for the year ended December 31, 2000 and the nine months ended September 30, 2001 give effect to the following as if each transaction had occurred as of the beginning of the period presented and the pro forma combined condensed balance sheet as of September 30, 2001 gives effect to the following as if each transaction had occurred on September 30, 2001: - the exclusion of revenues and costs under an industrial power supply contract that is contractually excluded from the MPC Utility; - the implementation of the termination of a special retirement incentive plan that was contractually required to be terminated as part of the acquisition of the MPC Utility; - the elimination of certain regulatory liabilities relating to the sale by Montana Power of its oil and gas businesses, which liabilities are being retained by Montana Power and for which Montana Power is fully indemnifying NorthWestern as part of the acquisition of the MPC Utility; - the elimination of dividends paid on Montana Power's preferred stock, which stock is being retained by Montana Power as part of the acquisition of the MPC Utility; and The Unaudited Pro Forma Combined Condensed Statements of Income as presented include - the impact of an interim combined general electric and natural gas rate increase of $19.8 million per annum, granted on November 28, 2000 and lasting until May 8, 2001; and - the impact of a final combined general electric and natural gas rate increase of $20.3 million per annum approved by the MPSC on May 8, 2001. This final rate increase replaced the interim rate increase described above. In addition, as a result of legislation enacted in Montana in 2001, recovery of that portion of power supply costs related to certain qualified facilities which are currently not recovered in rates, as reflected in the Unaudited Consolidated Pro Forma Statements of Income, are anticipated to be recovered in rates in future periods. The Unaudited Consolidated Pro Forma Statements of Income for the nine months ended September 30, 2001 reflect an offsetting one-time adjustment related to the recording of a regulatory asset which resulted from the final settlement of the aforementioned general rate increase approved by the MPSC on May 8, 2001. The pro forma adjustments are based upon currently available information and certain assumptions that our management believe are reasonable. The unaudited pro forma financial information is prepaid for illustrative purposes only and is not necessarily indicative of the operating results or financial condition of the MPC Utility that would have occurred had the transactions occurred at the periods presented, nor is the unaudited pro forma financial information necessarily indicative of future operating results or the future financial position of the MPC Utility. Pro forma results for the nine months ended September 30, 2001 are not necessarily indicative of the results that may be expected for a full year. Certain pro forma adjustments are based, in part, on the impact of the terms and conditions of the Unit Purchase Agreement governing our acquisition of the MPC Utility, and we cannot assure you that such terms and conditions will remain unchanged. Pro forma adjustments exclude certain cash accounts representing excess proceeds from the Montana Power's previous sale of generation assets, which cash will be applied to reduce transition and stranded costs under the jurisdiction of the Montana Public Service Commission and the Federal Energy Regulatory Commision. S-63 MONTANA POWER COMPANY UTILITY UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL DATA You should read the following tables in conjunction with the combined financial statements and notes thereto of The Utility of The Montana Power Company as of December 31, 2000 and 1999 and for each of the years in the three-year period ended December 31, 2000 the unaudited combined financial statements and the notes thereto of The Utility of The Montana Power Company as of September 30, 2001 and for the nine months ended September 30, 2001 included in NorthWestern's Current Report on Form 8-K, dated December 12, 2001, included in Exhibit 99.1 hereto. S-64 MONTANA POWER COMPANY UTILITY UNAUDITED COMBINED CONDENSED PRO FORMA STATEMENTS OF INCOME (in thousands)
FOR THE YEAR ENDED FOR THE NINE MONTHS ENDED DECEMBER 31, 2000 SEPTEMBER 30, 2001 ----------------------------------------- ---------------------------------------- MPC UTILITY PRO FORMA PRO FORMA MPC UTILITY PRO FORMA PRO FORMA ACTUAL(1) ADJUSTMENTS MPC UTILITY ACTUAL(1) ADJUSTMENTS MPC UTILITY ----------- ------------- ----------- ----------- ----------- ----------- OPERATING REVENUES.............. $676,053 $(47,909)(2) $628,144 $536,306 $(45,655)(2) $490,651 COST OF SALES................... 378,834 (59,329)(2) 319,505 379,916 (131,744)(2) 248,172 ---------- ----------- ---------- ---------- ---------- ---------- GROSS MARGIN.................... 297,219 11,420 308,639 156,390 86,089 242,479 ---------- ----------- ---------- ---------- ---------- ---------- OPERATING EXPENSES: Selling, general and administrative expenses..... 228,999 (10,267)(3) 186,183 148,417 (23,800)(4) 124,617 Depreciation and amortization................ 54,123 (32,549)(4) 54,123 42,765 42,765 ---------- ----------- ---------- ---------- ---------- ---------- 283,122 (42,816) 240,306 191,182 (23,800) 167,382 ---------- ----------- ---------- ---------- ---------- ---------- OPERATING INCOME (LOSS)......... 14,097 54,236 68,333 (34,792) 109,889 75,097 Interest expense................ (35,880) (35,880) (24,721) (24,721) Investment income and other..... 14,481 14,481 1,707 1,707 ---------- ----------- ---------- ---------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS..................... (7,302) 54,236 46,934 (57,806) 109,889 52,083 Benefit (provision) for income taxes......................... 19,599 (35,761) (16,162) 20,015 (38,721) (18,706) ---------- ----------- ---------- ---------- ---------- ---------- NET INCOME (LOSS)............... 12,297 18,475 30,772 (37,791) 71,168 33,377 Minority interest on preferred securities of subsidiary trust......................... (5,492) (5,492) (4,119) (4,119) Dividends on cumulative preferred stock............... (3,690) 3,690(5) (2,847) 2,847(5) ---------- ----------- ---------- ---------- ---------- ---------- EARNINGS ON COMMON STOCK........ $3,115 $22,165 $25,280 $(44,757) $74,015 $29,258 ========== =========== ========== ========== ========== ==========
The accompanying notes are an integral part of these combined condensed pro forma financial statements. S-65 MONTANA POWER COMPANY UTILITY UNAUDITED COMBINED CONDENSED PRO FORMA BALANCE SHEET (in thousands)
AT SEPTEMBER 30, 2001 -------------------------------------------------- AS ADJUSTED FOR MPC UTILITY PRO FORMA ACQUISITION BY ACTUAL(1) ADJUSTMENTS(6),(7) NORTHWESTERN ----------- ------------------ --------------- ASSETS CURRENT ASSETS: Cash and cash equivalents......................... $6,504 $6,504 Accounts receivable, net.......................... 110,348 $(55,909) 54,439 Inventories....................................... 11,508 11,508 Other current assets.............................. 109,944 (3,563) 106,381 PROPERTY, PLANT AND EQUIPMENT, NET.................. 1,092,178 1,092,178 GOODWILL AND OTHER INTANGIBLE ASSETS, NET........... 7,561 7,561 OTHER ASSETS: Investments....................................... 25,439 25,439 Other assets...................................... 226,471 226,471 ---------- ---------- ---------- $1,589,953 $(59,472) $1,530,481 ========== ========== ========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long-term debt.............. $6,930 $(3,531) $3,399 Short-term debt--Unrelated........................ 74,600 (74,600) Short-term debt--Associated companies............. 49,811 (49,811) Accounts payable--Unrelated....................... 37,162 37,162 Accrued expenses--Associated companies............ 75,809 (75,809) Accrued expenses.................................. 135,016 (1,460) 133,556 ---------- ---------- ---------- 379,328 (205,211) 174,117 Long-term debt...................................... 306,188 113,413(6) 419,601 Deferred income taxes............................... 86,422 (86,422) Other noncurrent liabilities........................ 380,947 380,947 Company obligated mandatorily redeemable securities of trust holding solely parent debentures......... 65,000 65,000 SHAREHOLDERS' EQUITY: Preferred stock................................... 57,654 (57,654) Other equity...................................... 314,414 176,402 490,816 ---------- ---------- ---------- $1,589,953 $(59,472) $1,530,481 ========== ========== ==========
The accompanying notes are an integral part of these combined condensed pro forma financial statements. S-66 MONTANA POWER COMPANY UTILITY NOTES TO UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL DATA The Unaudited Pro Forma Combined Condensed Financial Data of the MPC Utility are based on the following assumptions: (1) MPC Utility reflects the electric and natural gas transmission and distribution utility operations and certain unregulated, energy-related businesses (including Colstrip Unit 4) of Montana Power that provide products and services to industrial, institutional and commercial customers. These operations and businesses are discussed in the audited financial statements for The Utility of the Montana Power Company that NorthWestern has filed with the SEC in its Current Report on Form 8-K, dated December 12, 2001, which are incorporated by reference herein. These entities represent the entities which will be part of the pending sale to NorthWestern and are collectively referred to as the MPC Utility. (2) Reflects the elimination of $47.9 million of revenues and $59.3 million of associated power supply costs for the year ended December 31, 2000 and $45.7 million of revenues and $131.7 million of associated power supply and other costs for the nine months ended September 30, 2001 under an industrial power supply contract. Pursuant to the Unit Purchase Agreement, these associated revenues and costs have been excluded. The Unit Purchase Agreement requires the power supply contract and all obligations related thereto to remain with Montana Power and is not part of the MPC Utility being acquired by Northwestern. Montana Power has terminated two other supply contracts which had combined revenues of $4.7 million and associated power supply costs of $10.0 million for the year ended December 31, 2000 and combined revenues of $4.3 million and associated power supply costs of $8.6 million for the nine months ended September 30, 2001. Because these contracts were not specifically required to be terminated by the Unit Purchase Agreement, the pro forma statements of income have not been adjusted to exclude the losses on these contracts. (3) Reflects $10.3 million of expense from a reduction in actual salary and benefit costs for the year ended December 31, 2000 resulting from the termination of a special retirement incentive plan. Montana Power is required to terminate this special retirement plan pursuant to the Unit Purchase Agreement. (4) On October 31, 2000, Montana Power sold its oil and natural gas businesses. As a result of the transaction, Montana Power recorded a regulatory liability of $32.5 million in the fourth quarter of 2000 representing the portion of the proceeds from the sale of oil and natural gas businesses, which Montana Power believed was attributable to properties previously included in the natural gas utility rate base. An additional $23.8 million liability was recorded in the third quarter of 2001. NorthWestern is specifically indemnified, pursuant to the Unit Purchase Agreement, of any impact relating to the regulatory treatment of the gain on the sale of the oil and gas businesses. Therefore, the pro forma adjustment reflects the reversal of the $32.5 million charge in 2000 and the $23.8 million charge in the nine months ended September 30, 2001. (5) Reflects the elimination of $3.7 million of dividends for the year ended December 31, 2000 and $2.8 million of dividends for the nine months ended September 30, 2001 on preferred stock which will not be assumed by NorthWestern pursuant to the Unit Purchase Agreement. (6) On November 27, 2001, Montana Power issued $150 million aggregate principal amount of its 7.30% First Mortgage Bonds due 2006. Pursuant to the Unit Purchase Agreement with NorthWestern, which requires that NorthWestern assume no more than $488 million in debt and preferred securities of the MPC Utility, the Unaudited Pro Forma Combined Condensed Balance Sheet does not reflect the proceeds from that offering. Instead, the Unaudited Pro Forma Combined Condensed Balance Sheet S-67 MONTANA POWER COMPANY UTILITY NOTES TO UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL DATA adjusts Long-Term Debt such that the aggregate amount of debt and preferred securities assumed by NorthWestern upon closing of the pending acquisition equals $488 million. (7) Reflects purchase adjustments to the assets and liabilities of the MPC Utility to reflect the effect of the pending acquisition accounted for as a business purchase and to exclude certain assets and liabilities pursuant to the Unit Purchase Agreement. (8) Certain pro forma adjustments are based, in part, on the impact of the terms and conditions of the Unit Purchase Agreement governing our acquisition of the MPC Utility, and we cannot assure you that such terms and conditions will remain unchanged. Pro forma adjustments exclude certain cash accounts representing excess proceeds from Montana Power's previous sale of generation assets, which cash will be applied to reduce transition and stranded costs under the jurisdiction of the MPSC and FERC. S-68 -----END PRIVACY-ENHANCED MESSAGE-----