-----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, OYoWoy/H7FsXqmlkLyhsvs0gE/9kg7Myh4CmuOwSscLnnX/DfDDK11ENzlrZX4Kt bmiDVnZbDI05iTkkwTOYjw== 0000081023-01-500065.txt : 20010815 0000081023-01-500065.hdr.sgml : 20010815 ACCESSION NUMBER: 0000081023-01-500065 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010630 FILED AS OF DATE: 20010814 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF NEW MEXICO CENTRAL INDEX KEY: 0000081023 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 850019030 STATE OF INCORPORATION: NM FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-06986 FILM NUMBER: 1713602 BUSINESS ADDRESS: STREET 1: ALVARADO SQUARE, MS2706 CITY: ALBUQUERQUE STATE: NM ZIP: 87158 BUSINESS PHONE: 5058482700 10-Q 1 f10q_06302001.txt 10-Q JUNE 30, 2001 FILING UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITES EXCHANGE ACT OF 1934 For the period ended June 30, 2001 ------------- - OR - [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _________________ Commission file number 1-6986 ------ PUBLIC SERVICE COMPANY OF NEW MEXICO ------------------------------------ (Exact name of registrant as specified in its charter) New Mexico 85-0019030 ---------- ---------- (State or other jurisdiction of (I.R.S. Employer Incorporation of organization) Identification No.) Alvarado Square, Albuquerque, New Mexico 87158 ---------------------------------------------- (Address of principal executive offices) (Zip Code) (505) 241-2700 -------------- (Registrant's telephone number, including area code) ------------------------------ Former name, former address and former fiscal year,if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock-$5.00 par value 39,117,799 shares ---------------------------- ----------------- Class Outstanding at August 1, 2001 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES INDEX Page No. PART I. FINANCIAL INFORMATION: Report of Independent Public Accountants.......................... 3 ITEM 1. FINANCIAL STATEMENTS Consolidated Statements of Earnings - Three Months and Six Months Ended June 30 2001 and 2000........... 4 Consolidated Balance Sheets - June 30, 2001 and December 31, 2000............................... 5 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2001 and 2000........................... 7 Notes to Consolidated Financial Statements........................ 8 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS............ 25 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.............................................. 60 PART II. OTHER INFORMATION: ITEM 1. LEGAL PROCEEDINGS........................................... 61 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 65 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................ 66 Signature ......................................................... 68 2 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Public Service Company of New Mexico: We have reviewed the accompanying condensed consolidated balance sheet of PUBLIC SERVICE COMPANY OF NEW MEXICO (a New Mexico corporation) and subsidiaries as of June 30, 2001, and the related condensed consolidated statements of earnings for the three-month and six-month periods ended June 30, 2001 and 2000, and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 2001 and 2000. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States. We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet and statement of capitalization of Public Service Company of New Mexico and subsidiaries as of December 31, 2000, and the related consolidated statements of earnings, and cash flows for the year then ended (not presented separately herein), and in our report dated January 26, 2001, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2000 is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. ARTHUR ANDERSEN LLP Albuquerque, New Mexico August 13, 2001 3 ITEM 1. FINANCIAL STATEMENTS PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, -------------------------- ------------------------- 2001 2000 2001 2000 ------------ ------------ ------------ ---------- (In thousands, except per share amounts) Operating Revenues: Utility..................................... $223,629 $184,833 $550,087 $405,477 Generation and Trading...................... 524,758 221,911 1,015,923 398,208 Unregulated businesses...................... 1,277 1,343 1,277 1,692 Intersegment elimination.................... (83,573) (79,046) (164,666) (155,045) ------------ ------------ ------------ ---------- Total operating revenues.................. 666,091 329,041 1,402,621 650,332 ------------ ------------ ------------ ---------- Operating Expenses: Cost of energy sold......................... 433,841 180,394 930,939 348,117 Energy production costs..................... 38,766 35,906 78,256 71,548 Administrative and general.................. 37,879 33,562 72,903 65,758 Depreciation and amortization............... 23,929 22,633 48,148 46,642 Transmission and distribution costs......... 15,081 14,795 30,357 30,076 Income 28,209 5,632 69,115 13,459 taxes...................................... Taxes, other than income taxes.............. 7,839 8,465 15,056 16,131 ------------ ----------- ------------ ---------- Total operating expenses.................. 585,544 301,387 1,244,774 591,731 ------------ ----------- ------------ ---------- Operating income.......................... 80,547 27,654 157,847 58,601 ------------ ----------- ------------ ---------- Other Income and Deductions Other....................................... (21,866) 10,806 (17,506) 23,185 Income taxes................................ 7,278 (4,053) 5,552 (8,927) ------------ ----------- ------------ ---------- Net other income and deductions........... (14,588) 6,753 (11,954) 14,258 ------------ ------------ ------------ ---------- Income before interest charges............ 65,959 34,407 145,893 72,859 ------------ ------------ ------------ ---------- Interest Charges: Interest on long-term debt.................. 15,723 15,676 31,366 31,457 Other interest charges...................... 639 745 1,378 1,464 ------------ ------------ ------------ ---------- Interest charges.......................... 16,362 16,421 32,744 32,921 ------------ ------------ ------------ ---------- Net Earnings.................................. 49,597 17,986 113,149 39,938 Preferred Stock Dividend Requirements......... 147 147 293 293 ------------ ------------ ------------ ---------- Net Earnings Applicable to Common Stock....... $ 49,450 $ 17,839 $112,856 $ 39,645 ============ ============ ============ ========== Net Earnings per Common Share: Basic....................................... $ 1.26 $ 0.45 $ 2.89 $ 1.00 ============ ============ ============ ========== Diluted..................................... $ 1.24 $ 0.45 $ 2.84 $ 1.00 ============ ============ ============ ========== Dividends Paid per Share of Common Stock...... $ 0.20 $ 0.20 $ 0.40 $ 0.40 ============ ============ ============ ==========
The accompanying notes are an integral part of these financial statements. 4 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
June 30, December 31, 2001 2000 ------------- ------------ (Unaudited) (In thousands) ASSETS Utility Plant: Electric plant in service.................................... $2,028,204 $2,030,813 Gas plant in service......................................... 556,274 553,755 Common plant in service and plant held for future use........ 38,714 36,678 ------------- ------------ 2,623,192 2,621,246 Less: accumulated depreciation and amortization............. 1,195,167 1,153,377 ------------- ------------ 1,428,025 1,467,869 Construction work in progress................................ 226,040 123,653 Nuclear fuel, net of accumulated amortization of $18,430 and $19,081...................................... 26,526 25,784 ------------- ------------ Net utility plant.......................................... 1,680,591 1,617,306 ------------- ------------ Other Property and Investments: Other investments............................................ 460,182 479,821 Non-utility property, net of accumulated depreciation of $1,816 and $1,644........................................ 2,571 3,666 ------------- ------------ Total other property and investments....................... 462,753 483,487 ------------- ------------ Current Assets: Cash and cash equivalents.................................... 233,320 107,691 Accounts receivables, net of allowance for uncollectible accounts of $8,580 and $8,963............................ 285,434 242,742 Other receivables............................................ 54,711 64,857 Inventories.................................................. 36,737 36,091 Regulatory assets............................................ 4,148 47,604 Other current assets......................................... 62,510 11,417 ------------- ------------ Total current assets....................................... 676,860 510,402 ------------- ------------ Deferred Charges: Regulatory assets............................................ 203,883 226,849 Prepaid benefit costs........................................ 21,337 18,116 Other deferred charges....................................... 28,108 38,073 ------------- ------------ Total deferred charges..................................... 253,328 283,038 ------------- ------------ $ 3,073,532 $ 2,894,233 ============= ============
The accompanying notes are an integral part of these financial statements. 5 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
June 30, December 31, 2001 2000 --------------- -------------- (Unaudited) CAPITALIZATION AND LIABILITIES (In thousands) Capitalization: Common stockholders' equity: Common stock................................................... $ 195,589 $ 195,589 Additional paid-in capital..................................... 429,539 432,222 Accumulated other comprehensive income, net of tax............. (19,798) (27) Retained earnings.............................................. 401,869 296,843 --------------- -------------- Total common stockholders' equity........................... 1,007,199 924,627 Minority interest................................................. 11,926 12,211 Cumulative preferred stock without mandatory redemption requirements...................................... 12,800 12,800 Long-term debt, less current maturities........................... 953,854 953,823 --------------- -------------- Total capitalization........................................ 1,985,779 1,903,461 --------------- -------------- Current Liabilities: Accounts payable.................................................. 259,071 257,991 Accrued interest and taxes........................................ 85,699 36,889 Other current liabilities......................................... 154,129 67,758 --------------- -------------- Total current liabilities................................... 498,899 362,638 --------------- -------------- Deferred Credits: Accumulated deferred income taxes................................... 112,626 166,249 Accumulated deferred investment tax credits......................... 46,284 47,853 Regulatory liabilities.............................................. 64,179 65,552 Regulatory liabilities related to accumulated deferred income tax... 14,144 20,696 Accrued postretirement benefit costs................................ 22,675 11,899 Other deferred credits.............................................. 328,946 315,885 --------------- -------------- Total deferred credits........................................... 588,854 628,134 --------------- -------------- $3,073,532 $2,894,233 =============== ==============
The accompanying notes are an integral part of these financial statements. 6 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Six Months Ended June 30, ------------------------------ 2001 2000 -------------- -------------- (In thousands) Cash Flows From Operating Activities: Net earnings...................................................... $ 113,149 $ 39,938 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization................................. 53,083 51,930 Other, net.................................................... 29,117 8,469 Changes in certain assets and liabilities: Accounts receivables........................................ (42,693) (25,475) Other assets................................................ 31,405 7,714 Accounts payable............................................ 1,081 (1,239) Accrued taxes............................................... 48,698 (161) Other liabilities........................................... 23,641 15,694 -------------- -------------- Net cash flows provided from operating activities........... 257,481 96,870 -------------- -------------- Cash Flows Used for Investing Activities: Utility plant additions........................................... (115,941) (50,365) Return on PVNGS lease obligation bonds............................ 8,535 8,636 Other investing................................................... (5,544) (23,311) -------------- -------------- Net cash flows used for investing activities................ (112,950) (65,040) -------------- -------------- Cash Flows Used for Financing Activities: Repayments........................................................ - (32,800) Common stock repurchase........................................... - (18,854) Exercise of employee stock options................................ (2,682) - Dividends paid.................................................... (15,935) (16,227) Other financing................................................... (285) (288) -------------- -------------- Net cash flows used for financing activities................ (18,902) (68,169) -------------- -------------- Increase (Decrease) in Cash and Cash Equivalents.................... 125,629 (36,339) Beginning of Period................................................. 107,691 120,399 -------------- -------------- End of Period....................................................... $233,320 $ 84,060 ============== ============== Supplemental Cash Flow Disclosures: Interest paid..................................................... $ 31,382 $ 32,854 ============== ============== Income taxes paid, net ........................................... $ 52,150 $ 20,423 ============== ==============
The accompanying notes are an integral part of these financial statements. 7 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Accounting Policies and Responsibilities for Financial Statements In the opinion of management of Public Service Company of New Mexico (the "Company"), the accompanying interim consolidated financial statements present fairly the Company's financial position at June 30, 2001 and December 31, 2000, the consolidated results of its operations for the three months and six months ended June 30, 2001 and 2000 and the consolidated statements of cash flows for the six months ended June 30, 2001 and 2000. These statements are presented in accordance with the rules and regulations of the United States Securities and Exchange Commission ("SEC"). Accordingly, they are unaudited, and certain information and footnote disclosures normally included in the Company's annual consolidated financial statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these statements should refer to the Company's audited consolidated financial statements and notes thereto for the year ended December 31, 2000, which are included on the Company's Annual Report on Form 10-K for the year ended December 31, 2000. The results of operations presented in the accompanying financial statements are not necessarily representative of operations for an entire year. Certain amounts in the 2000 consolidated financial statements and notes have been reclassified to conform to the 2001 financial statement presentation. (2) Nature of Business and Segment Information The Company is an investor-owned integrated utility engaged in the generation, transmission, distribution and sale and trading of electricity, and the transportation, distribution and sale of natural gas. In addition, the Company provides energy and utility related services under its wholly-owned subsidiary, Avistar, Inc. ("Avistar"). The Company's principal business segments are Utility Operations, which include the Electric Product Offering ("Electric") and the Natural Gas Product Offering ("Gas"), and Generation and Trading Operations ("Generation and Trading"). Electric consists of two major business lines that include distribution and transmission. The transmission business line does not meet the definition of a segment due to its immateriality and is combined with the distribution business line for disclosure purposes. Electric procures all of its electric power needs from the Company's Generation and Trading Operations. These intersegment sales are priced using internally developed transfer pricing, and are not based on market rates. Customer electric rates are regulated by the New Mexico Public Regulation Commission ("PRC") and determined on a basis that includes the recovery of the cost of power production by the Company's Generation and Trading Operations and a return on the related assets, among other things. 8 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (2) Nature of Business and Segment Information (Continued) UTILITY OPERATIONS Electric The Company provides jurisdictional retail electric service to a large area of north central New Mexico, including the cities of Albuquerque and Santa Fe, and certain other areas of New Mexico. The Company owns or leases 2,887 circuit miles of transmission lines, interconnected with other utilities in New Mexico and east and south into Texas, west into Arizona, and north into Colorado and Utah. Gas The Company's gas operations distribute natural gas to most of the major communities in New Mexico, including Albuquerque and Santa Fe. The Company's customer base includes both sales-service customers and transportation-service customers. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. GENERATION AND TRADING OPERATIONS The Company's generation and trading operations serve four principal markets. These include sales to the Company's Utility Operations to cover jurisdictional electric demand, sales to firm-requirements wholesale customers, other contracted sales to third parties for a specified amount of capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of time and energy sales made on an hourly basis at fluctuating, spot-market rates. These latter two markets constitute the Company's power trading operations. As of June 30, 2001 the total net generation capacity of facilities owned or leased by the Company was 1,653 MW, including a 132 MW power purchase contract accounted for as an operating lease. In addition to its generation capacity, the Company purchases power in the open market. UNREGULATED The Company's wholly-owned subsidiary, Avistar, was formed in August 1999 as a New Mexico corporation and is currently engaged in certain unregulated business ventures. Unregulated also includes certain corporate activities, which are not material. REGULATION AND RESTRUCTURING In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delay the original implementation dates by approximately five years, including the requirement for corporate separation of certain activities to be deregulated from activities 9 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (2) Nature of Business and Segment Information (Continued) regulated by the PRC. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. The amendments to the Restructuring Act require that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of the regulated and deregulated activities, by July 1, 2001. In addition, the amendments allow utilities to engage in unregulated power generation business activities until corporate separation is implemented. The Company believes that its ability to form a new holding company and expand generation assets in an unregulated environment will give it the flexibility it needs to pursue its strategic plan despite the delay in customer choice and corporate separation. The Company is unable to predict the form its restructuring will take under the delayed implementation of customer choice. The formulation of a restructuring plan will be dependent on future business conditions at the expected time customer choice is implemented (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Issues Facing The Company - Recovery of Certain Costs Under The Restructuring Act" below). In June 2000, shareholders approved the mandatory share exchange necessary to implement a holding company structure, with the holding company to be named Manzano Corporation. In April 2001, the Company's Board of Directors amended the articles of incorporation of the proposed holding company to rename the holding company "PNM Resources, Inc." (PNM Resources). In April 2001, the Company filed its application for the creation of a holding company under the terms of the Restructuring Act, as amended. Hearings on the matter occurred in mid May. The PRC issued an order approving formation of a holding company on June 28, 2001. The order limits the Company's proposed utility subsidiary's ability to pay dividends to the parent holding company without prior PRC approval to annual current earnings determined on a rolling four quarter average and imposes certain regulatory requirements on the construction of merchant generation plants. The Company believes that certain conditions imposed by the PRC order are unnecessarily burdensome and could have an adverse effect on the Company's ability to execute its growth strategy. On July 27, 2001, the Company asked the PRC to reconsider certain conditions imposed by the order. The PRC has until August 16 to respond to the Company's request for rehearing. If the PRC does not act by then, the request is automatically denied. The Company is unable to predict the outcome of this proceeding. If the result of the Company's request for rehearing is unfavorable, the Company will consider filing an appeal to the New Mexico Supreme Court. RISKS AND UNCERTAINTIES The Company's future results may be affected by changes in regional economic conditions; fluctuations in fuel, purchased power and gas prices; the actions of utility regulatory 10 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (2) Nature of Business and Segment Information (Continued) commissions; including rulings regarding price mitigation; changes in law; environmental regulations and external factors such as the weather. As a result of State and Federal regulatory reforms, the public utility industry is undergoing a fundamental change. As this occurs, the electric generation business is transforming into a competitive marketplace. In turn, these reforms are being revisited as a result of the energy crisis in California, escalating prices for power elsewhere in the Western United States, and concerns over inadequate capacity, among other conditions. The Company's future results will be impacted by its ability to recover its stranded costs, the market price of electricity and natural gas costs incurred previously in providing power generation to electric service customers, the costs of transition to an unregulated status, future regulatory actions, and the price of power in the wholesale markets. In addition, as a result of deregulation, the Company may face competition from companies with greater financial and other resources. Summarized financial information by business segment for the three months ended June 30, 2001 and 2000 is as follows:
Utility ------------------------------------ Generation Electric Gas Total and Trading Unregulated Consolidated -------- --- ----- ----------- ----------- ------------ (In thousands) 2001: Operating revenues: External customers............. $136,368 $87,084 $223,452 $441,362 $ 1,277 $666,091 Intersegment revenues.......... 177 - 177 83,396 - 83,573 Depreciation and amortization..... 8,066 5,333 13,399 10,521 9 23,929 Interest income................... 543 264 807 10,029 2,088 12,924 Interest charges.................. 4,280 2,956 7,236 9,096 30 16,362 Operating income.................. 14,598 3,244 17,842 59,656 3,049 80,547 Income tax expense (benefit) From continuing operations...... 5,998 268 6,266 31,101 (16,436) 20,931 Segment net income (loss)......... 9,154 408 9,562 47,459 (7,424) 49,597 Total assets...................... 743,780 467,970 1,211,750 1,585,635 276,147 3,073,532 Gross property additions.......... 17,065 10,884 27,949 23,916 4,696 56,561 2000: Operating revenues: External customers............. $130,142 $ 54,514 $184,656 $143,042 $ 1,343 $329,041 Intersegment revenues.......... 177 - 177 78,869 - 79,046 Depreciation and amortization..... 7,720 4,515 12,235 10,391 7 22,633 Interest income................... 347 110 457 9,743 2,171 12,371 Interest charges.................. 4,383 2,881 7,264 9,013 144 16,421 Operating income (loss)........... 15,605 1,961 17,566 16,594 (6,506) 27,654 Income tax expense (benefit) from continuing operations...... 7,034 (427) 6,607 6,853 (3,775) 9,685 Segment net income (loss)......... 11,131 (836) 10,295 12,818 (5,127) 17,986 Total assets...................... 745,776 442,892 1,188,668 1,449,638 120,659 2,758,965 Gross property additions.......... 12,092 6,475 18,567 9,438 2,335 30,340
11 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (2) Nature of Business and Segment Information (Continued) Summarized financial information by business segment for the six months ended June 30, 2001 and 2000 is as follows:
Utility ---------------------------------- Generation Electric Gas Total and Trading Unregulated Consolidated -------- --- ----- ----------- ----------- ------------ (In thousands) 2001: Operating revenues: External customers............. $270,714 $279,020 $549,734 $851,610 $ 1,277 $1,402,621 Intersegment revenues.......... 353 - 353 164,313 - 164,666 Depreciation and amortization..... 16,091 10,623 26,714 21,416 18 48,148 Interest income................... 1,000 551 1,551 19,705 3,881 25,137 Interest charges.................. 8,553 5,942 14,495 18,191 58 32,744 Operating income (loss)........... 30,390 14,631 45,021 118,684 (5,858) 157,847 Income tax expense (benefit) From continuing operations...... 13,698 5,950 19,648 66,873 (22,958) 63,563 Segment net income (loss)......... 20,901 9,080 29,981 102,046 (18,878) 113,149 Total assets...................... 743,780 467,970 1,211,750 1,585,635 276,147 3,073,532 Gross property additions.......... 28,505 17,458 45,963 59,251 6,159 111,373 2000: Operating revenues: External customers............. $256,064 $149,060 $405,124 $243,516 $ 1,692 $650,332 Intersegment revenues.......... 353 - 353 154,692 - 155,045 Depreciation and amortization..... 16,047 9,881 25,928 20,703 11 46,642 Interest income................... 393 247 640 19,522 3,436 23,598 Interest charges.................. 8,853 5,735 14,588 18,028 305 32,921 Operating income (loss)........... 29,637 10,079 39,716 30,289 (11,404) 58,601 Income tax expense (benefit) from continuing operations...... 12,939 3,299 16,238 12,666 (6,518) 22,386 Segment net income (loss)......... 20,537 4,664 25,201 24,048 (9,311) 39,938 Total assets...................... 745,776 442,892 1,188,668 1,449,638 120,659 2,758,965 Gross property additions.......... 21,937 11,212 33,149 17,216 2,834 53,199
12 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (3) Comprehensive Income Changes in comprehensive income are as follows:
Three Months Ended Six Months Ended June 30, June 30, ------------------------- --------------------------- 2001 2000 2001 2000 ------------ ------------ ------------ ------------ (In thousands) Net Earnings......................................... $49,597 $17,986 $113,149 $39,938 ------------ ------------ ------------ ------------ Other Comprehensive Income, net of tax: Unrealized gain (loss) on securities: Unrealized holding gains (losses) arising during the period................................... 935 614 (13) 1,940 Less reclassification adjustment for gains.... (151) (1,153) (447) (2,503) Minimum pension liability adjustment............... 780 - - - Mark-to-market adjustment for certain derivative transactions (see Footnote 4) Initial implementation of SFAS 133 designated cash flow hedges................. 6,148 - - - Change in fair market value of designated cash flow hedges................. (35,954) (26,239) - - ------------ ------------ ------------ ------------ Total Other Comprehensive Income (Loss)........... (35,170) (539) (19,771) (563) ------------ ------------ ------------ ------------ Total Comprehensive Income........................... $14,427 $17,447 $93,378 $39,375 ============ ============ ============ ============
The Company's investments held in grantor trusts for nuclear decommissioning and certain retirement benefits are classified as available-for-sale, and accordingly unrealized holding gains and losses are recognized as a component of comprehensive income. Realized gains and losses are included in earnings. Net losses to the Company's pension plans not yet recognized as net periodic pension costs (or additional minimum liability) are reported as a component of comprehensive income. Changes in the liability are adjusted as necessary. All components of comprehensive income are recorded, net of any tax benefit or expense. A deferred asset or liability is established for the resulting temporary difference. (4) Financial Instruments The Company implemented Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"), as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at their fair value. SFAS 133, as amended, also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset related results on the hedged item in the income statement, 13 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (4) Financial Instruments (Continued) and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices and adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. The Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to assess and monitor the financial conditions of counterparties. The Company's credit risk with its largest counterparty as of June 30, 2001 was $40.6 million. Natural Gas Contracts Utility Operations Pursuant to a 1997 order issued by the New Mexico Public Utility Commission ("NMPUC"), predecessor to the PRC, the Company's Utility Operations have previously and continue to hedge certain portions of natural gas supply contracts in order to protect the Company's natural gas customers from the risk of adverse price fluctuations in the natural gas market. The financial impacts of all hedge gains and losses from swaps are recoverable through the Company's purchased gas adjustment clause as deemed prudently incurred by the PRC. As a result, earnings are not affected by the gains or losses generated by these instruments. The Company continues to contract for gas price caps, a type of hedge, to protect its natural gas customers from price risk during the 2001-2002 heating season through the use of financial hedging tools. As of June 30, 2001, the Company expended approximately $9 million to purchase physical options that limit the maximum amount the Company would pay for gas during the winter heating season. Generation and Trading Operations The Company's Generation and Trading Operations conduct a hedging program to reduce its exposure to fluctuations in prices for natural gas used as a fuel source for some of its generation. In the first quarter of 2001, the Generation Operations purchased futures contracts for a portion of its anticipated natural gas needs in the second, third and fourth quarters. The futures contracts lock in the Company's natural gas purchase prices at $5.37 to $6.40 per 14 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (4) Financial Instruments (Continued) MMBTU and have a notional principal of $20.9 million. Simultaneously, a delivery location basis swap was purchased for quantities corresponding to the futures quantities to protect against price differential changes at the specific delivery points. The Company is accounting for these transactions as cash flow hedges; accordingly, gains and losses related to these transactions are deferred and recorded as a component of Other Comprehensive Income. These gains and losses are reclassified and recognized in earnings as an adjustment to the Company's cost of fuel when the hedged forecasted transaction affects earnings. The assessment of hedge effectiveness is based on the changes in the futures contract price as adjusted for the delivery point basis swap. There was no hedge ineffectiveness recognized in the six months ended June 30, 2001. Electricity Contracts To take advantage of market opportunities associated with the purchase and sale of electricity, the Company's Generation and Trading operations periodically enters into derivative financial instrument contracts. The Company generally accounts for these financial instruments as trading activities under the accounting guidelines set forth under The Emerging Issues Task Force ("EITF") Issue No. 98-10. As a result, these contracts are marked to market at the end of each period. The related gains and losses for these derivative instruments are recorded as adjustments to operating revenues. Through June 30, 2001, the Company's Generation and Trading operations settled trading contracts for the sale of electricity that generated $37.3 million of electric revenues by delivering 236 million KWh. The Company purchased $36.2 million or 216 million KWh of electricity to support these contractual sales and other open market sales opportunities. As of June 30, 2001, the Company's Generation and Trading operations had open trading contract positions to buy $122.1 million and to sell $56.8 million of electricity. At June 30, 2001, the Company had a gross mark-to-market gain (asset position) on these trading contracts of $41.8 million and a gross mark-to-market loss (liability position) of $72.6 million, with net mark-to-market losses of $30.8 million. The mark-to-market valuation is recognized in earnings each period. In addition, the Company's Generation and Trading operations enters into forward physical contracts for the sale of the Company's electric capacity in excess of its jurisdictional needs, including reserves, or the purchase of jurisdictional needs, including reserves, when resource shortfalls exist. The Company generally accounts for these derivative financial instruments as normal sales and purchases as defined by SFAS 133, as amended. The Company from time to time makes forward purchases to serve its jurisdictional needs when the cost of purchased power is less than the incremental cost of its generation. At June 30, 2001, the Company had open forward positions classified as normal sales of electricity of $349.4 million and normal purchases of electricity of $279.3 million. 15 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (4) Financial Instruments (Continued) The Company designated certain forward purchase contracts for electricity as cash flow hedges. The Company's designated cash flow hedges at June 30, 2001, were forward purchase contracts for the purchase of electric power for forecasted jurisdictional use during planned outages in 2001 and certain forecasted sales. The hedged risks associated with these instruments are the changes in cash flows related to forecasted purchase of electricity due to changes in the price of electricity on the spot market. Assessment of hedge effectiveness will be based on the changes in the forward price of electricity. There was no hedge ineffectiveness recognized in the three months ended June 30, 2001. The Company's Generation and Trading operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases. The Company's value-at-risk calculation considers this exposure (see "Item 3. Quantitative and Qualitative Disclosure About Market Risk"). Hedge of Trust Assets In February 2001, the Company terminated certain financial derivatives based on the Standard & Poor's ("S&P") 500 Index. These instruments were used to limit potential loss on investments for nuclear decommissioning, executive retirement and retiree medical benefits due to adverse market fluctuations. The Company recognized a realized gain of $0.5 million (pretax) as a result. Previously, the Company had marked-to-market the financial instruments to match the hedged investment activity. 16 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (5) Earnings Per Share In accordance with SFAS No. 128, Earnings per Share, dual presentation of basic and diluted earnings per share has been presented in the Consolidated Statements of Earnings. The following reconciliation illustrates the impact on the share amounts of potential common shares and the earnings per share amounts for June 30 (in thousands except per share amounts):
Three Months Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 ---------- ----------- ----------- ----------- Basic: Net Earnings.............................................. $49,597 $17,986 $113,149 $39,938 Preferred Stock Dividend Requirements..................... 147 147 293 293 ---------- ----------- ----------- ----------- Net Earnings Applicable to Common Stock................... $49,450 $17,839 $112,856 $39,645 ========== =========== =========== =========== Average Number of Common Shares Outstanding............... 39,118 39,536 39,118 39,754 ========== =========== =========== =========== Net Earnings per Common Share (Basic)..................... $ 1.26 $ 0.45 $ 2.89 $ 1.00 ========== =========== =========== =========== Diluted: Net Earnings Applicable to Common Stock Used in basic calculation............................... $49,450 $17,839 $112,856 $39,645 ========== =========== =========== =========== Average Number of Common Shares Outstanding............... 39,118 39,536 39,118 39,754 Diluted effect of common stock equivalents (a)............ 848 61 664 45 ---------- ----------- ----------- ----------- Average common and common equivalent shares Outstanding........................................... 39,966 39,597 39,782 39,799 ========== =========== =========== =========== Net Earnings per Share of Common Stock (Diluted).......... $ 1.24 $ 0.45 $ 2.84 $ 1.00 ========== =========== =========== ===========
(a) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money options of 141,660 and 162,066 for the three months and six months ended June 30, 2000. There were no anti-dilutive common stock equivalents in 2001. (6) Commitments and Contingencies Texas-New Mexico Power Wholesale Power Supply Contract In July 2001, the Company entered into a long-term wholesale power contract with Texas-New Mexico Power ("TNMP") to provide power to serve TNMP's firm retail customers. The contract has a term of 5 1/2 years commencing July 1, 2001. The Company will provide varying amounts of firm power on demand to complement existing TNMP contracts. As those contracts expire, the Company will replace them and become TNMP's sole supplier beginning January 1, 2003. In the last year of the contract, it is estimated that TNMP will need 114 megawatts of firm power. 17 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (6) Commitments and Contingencies (Continued) Construction Commitment The Company has committed to purchase combustion turbines totaling $126 million. The turbines are for planned power generation plants with an estimated cost of construction of approximately $245 million for which contracts have not been finalized. The Company has expended $37.3 million as of June 30, 2001. The planned plants are part of the Company's ongoing competitive strategy of increasing generation capacity over time. Such construction is not anticipated to be added to the rate base. Natural Gas Explosion On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. The cause of the leak is unknown and the Company is conducting an investigation into the explosion. One lawsuit against the Company for personal injuries by a person working in the building at the time of the explosion has been filed and served on the Company. Several claims for property and business interruption damages have been resolved by the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur. There can be no assurance that the outcome of this matter will not have a material adverse impact on the results of operations and financial position of the Company. Implementation of Customer Billing System On November 30, 1998, the Company implemented a new customer billing system. Due to a significant number of problems associated with the implementation of the new billing system, the Company was unable to generate appropriate bills for all its customers through the first quarter of 1999 and was unable to analyze delinquent accounts until November 1999. As a result of the delay of normal collection activities, the Company incurred a significant increase in delinquent accounts, many of which occurred with customers that no longer have active accounts with the Company. The Company continued its analysis and collection efforts of its delinquent accounts resulting from the problems associated with the implementation of the new customer billing system throughout 2000 and identified additional bad debt exposure. As a result, the Company significantly increased its estimated bad debt costs throughout 1999 and 2000. By the end of 2000, the Company completed its analysis of its delinquent accounts and resumed its normal collection procedures. In addition, due to the significantly higher natural gas prices experienced in November and December 2000, the Company increased its bad debt expense by approximately $1 million for the six months ended June 30, 2001 and $2 million for the year ended December 31, 2000 in anticipation of higher than normal delinquency rates. The Company expects this trend to continue as long as natural gas prices remain higher than historical levels. Based upon information available at June 30, 2001, the Company believes the allowance for doubtful accounts of $8.6 million is adequate for management's estimate of potential uncollectible accounts. 18 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (6) Commitments and Contingencies (Continued) The following is a summary of the allowance for doubtful accounts during the six months ended June 30, 2001 and the year ended December 31, 2000:
June 30, December 31, 2001 2000 ------------ ------------- Allowance for doubtful accounts, beginning of year.................................................... $ 8,963 $12,504 Bad debt expense............................................. 2,131 9,980 Less: Write off (adjustments) of uncollectible accounts..... 2,514 13,521 ------------ ------------- Allowance for doubtful accounts, end of year ................ $8,580 $ 8,963 ============ =============
PVNGS Liability and Insurance Matters The PVNGS participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under Federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the primary liability insurance limit, the Company could be assessed retrospective adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per reactor per incident. Based upon the Company's 10.2% interest in the three PVNGS units, the Company's maximum potential assessment per incident for all three units is approximately $27.0 million, with an annual payment limitation of $3 million per incident. If the funds provided by this retrospective assessment program prove to be insufficient, Congress could impose revenue raising measures on the nuclear industry to pay claims. The United States Nuclear Regulatory Commission and Congress are reviewing the related laws. The Company cannot predict whether or not Congress will change the law. However, certain changes could possibly trigger "Deemed Loss Events" under the Company's PVNGS leases, absent waiver by the lessors. Such an occurrence could require the Company to, among other things, (i) pay the lessor and the equity investor, in return for the investor's interest in PVNGS, cash in the amount as provided in the lease and (ii) assume debt obligations relating to the PVNGS lease. The PVNGS participants maintain "all-risk" (including nuclear hazards) insurance for nuclear property damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion as of January 1, 2001. The Company is a member of an industry mutual insurer which provides both the "all-risk" and increased cost of generation insurance to the Company. In the event of adverse losses experienced by this insurer, the Company is subject to an assessment. The Company's maximum share of any assessment is approximately $2.3 million per year. PVNGS Decommissioning Funding The Company has a program for funding its share of decommissioning costs for PVNGS. The nuclear decommissioning funding program is invested in equities and fixed 19 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (6) Commitments and Contingencies (Continued) income instruments in qualified and non-qualified trusts. The results of the 1998 decommissioning cost study indicated that the Company's share of the PVNGS decommissioning costs excluding spent fuel disposal will be approximately $180 million (in 2001 dollars). The estimated market value of the trusts at the end of June 30, 2001 was approximately $52 million. Nuclear Spent Fuel and Waste Disposal Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "Waste Act"), the United States Department of Energy ("DOE") is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by all domestic power reactors. Under the Waste Act, DOE was to develop the facilities necessary for the storage and disposal of spent nuclear fuel and to have the first facility in operation by 1998. DOE has announced that such a repository now cannot be completed before 2010. The operator of PVNGS has capacity in existing fuel storage pools at PVNGS which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of PVNGS through 2002, and believes it could augment that storage with the new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. The Company currently estimates that it will incur approximately $41 million (in 1998 dollars) over the life of PVNGS for its share of the fuel costs related to the on-site interim storage of spent nuclear fuel during the operating life of the plant. The Company accrues these costs as a component of fuel expense, meaning the charges are accrued as the fuel is burned. The operator of PVNGS currently believes that spent fuel storage or disposal methods will be available for use by PVNGS to allow its continued operation beyond 2002. Other There are various claims and lawsuits pending against the Company and certain of its subsidiaries. The Company is also subject to Federal, state and local environmental laws and regulations, and is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with business operations. It is not possible at this time for the Company to determine fully the effect of all litigation on its consolidated financial statements. However, the Company has recorded a liability where the litigation effects can be estimated and where an outcome is considered probable. The Company does not expect that any known lawsuits, environmental costs and commitments will have a material adverse effect on its financial condition or results of operations. (7) Environmental Issues The normal course of operations of the Company necessarily involves activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in 20 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (7) Environmental Issues (Continued) some instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred. Sources of potential environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes. The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, the Company, records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts). The Company's recorded estimated minimum liability to remediate its identified sites is $6.8 million. The ultimate cost to clean up the Company's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur. The Company believes that, due to these uncertainties, it is remotely possible that cleanup costs could exceed its recorded liability by up to $11.6 million. The upper limit of this range of costs was estimated using assumptions least favorable to the Company. In 2001, the Company anticipates spending $1.4 million for remediation and $0.7 million for control and prevention. The majority of the June 30, 2001 environmental liability is expected to be paid over the next five years, funded by cash generated from operations. Future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company. (8) Proposed Acquisition On November 9, 2000, the Company and Western Resources, Inc. ("Western Resources") announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. Due to recent actions by the Kansas Corporation Commission ("KCC"), the Company believes that the transaction cannot be accomplished under the terms of the present acquisition agreement if the orders remain in effect (see below). Present Acquisition Agreement Under the present agreement, the Company and Western Resources, whose utility operations consist of its Kansas Power and Light division and Kansas Gas and Electric subsidiary, will both become subsidiaries of a new holding company to be named at a future date. Prior to the consummation of this combination, Western Resources will reorganize all of its non-utility assets, including its 85 percent stake in Protection One and its 45 percent investment in ONEOK, into Westar Industries which will be spun off to Western Resources' shareholders, prior to the acquisition of Western's electric utility businesses by the Company. 21 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (8) Proposed Acquisition (Continued) Under the present agreement, the new holding company will issue 55 million of its shares, subject to adjustment, to Western Resources' shareholders and Westar Industries. Before any adjustments, the new company will have approximately 94 million shares outstanding, of which approximately 41 percent will be owned by former Company shareholders and 59 percent will be owned by former Western Resources shareholders and Westar Industries. In the present transaction, each Company share will be exchanged on a one-for-one basis for shares in the new holding company. Each Western Resources share will be exchanged for a fraction of a share of the new company. This exchange ratio will be finalized at closing, depending on the impact of certain adjustments to the transaction consideration. Under the present agreement, Western Resources and Westar have been given an incentive to reduce Western Resources net debt balance prior to the consummation of the transaction by selling non-utility assets or through other debt reduction activities. The present agreement contains a mechanism to adjust the transaction consideration based on certain activities not affecting the utility operations, which increase the equity of the utility. In addition, Westar Industries has the option of making equity infusions into Western Resources that will be used to reduce the utility's net debt balance prior to closing. Up to $407 million of the equity infusions may be used to purchase additional new holding company common and convertible preferred stock. The effect of these activities would be to increase the number of new holding company shares to be issued to all Western Resources shareholders (including Westar Industries) in the present transaction. In February 2001, Westar purchased 14.4 million Western Resources common shares at $24.358 per share (based on a 20 day look-back price at February 28, 2001) at an aggregate price of $350 million. As a result of this equity contribution, under the present agreement, the acquisition consideration may be adjusted to include an additional 4.3 million shares of the new holding company depending on the impact of future transactions between Western Resources and Westar. Under the present agreement, the transaction will be accounted for as a reverse acquisition by the Company as Western Resources shareholders will receive the majority of the voting interests in the new holding company. For accounting purposes Western Resources will be treated as the acquiring entity. Accordingly, all of the assets and liabilities of the Company will be recorded at fair value in the business combination as required by the purchase method of accounting. In addition, the operations of the Company will be reflected in the reported results of the combined company only from the date of acquisition. 22 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (8) Proposed Acquisition (Continued) Based on the volume weighted average closing price of the Company's common stock over the two days prior and two days subsequent to the announcement of the transaction of $24.149 per share, the indicated equity consideration of the present transaction is approximately $945 million, excluding the potential issuance of additional shares discussed above. There is approximately $2.9 billion of existing Western Resources debt giving the transaction an aggregate enterprise value of approximately $3.8 billion. There are plans for the new holding company to reduce and refinance a portion of the Western Resources debt, assumed in the present transaction. Under the present agreement, the successful split-off of Westar Industries from Western Resources is required prior to the consummation of the transaction. The present transaction is also conditioned upon, among other things, approvals from both companies' shareholders and customary regulatory approvals from the KCC, the PRC, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Federal Communications Commission and either the Federal Trade Commission or the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In addition, an adverse regulatory outcome related to other actions involving rate making or approval of regulatory plans may affect the consummation of the transaction. The new holding company is expected to register as a holding company with the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. Recent Actions by the KCC On July 20, 2001, the KCC issued an order prohibiting Western from proceeding with the split-off of Westar Industries. The KCC ruled that the split-off, as presently designed, is inconsistent with the public interest. The KCC also ruled that the adverse impacts of the split-off on ratepayers could not be cured by a merger and directed Western to file a financial plan within 90 days to restore Western's financial ratings to the investment grade level of similarly situated electric public utilities. Western has filed for reconsideration of the order. On July 25, 2001, the KCC issued an order reducing the rates of Western's electric utilities by the net amount of $22.7 million annually. Western had sought a combined increase of approximately $151 million annually. Other recommendations in the case would have reduced rates by up to $92 million annually. Western has filed for reconsideration of the order. On July 30, 2001, the Company and Western issued a joint release stating that the transaction as presently designed would be difficult to accomplish if the KCC orders remain in effect. The release announced that the Company and Western would begin discussions on how to modify the transaction to address KCC concerns. On August 13, 2001, the Company announced that Western had decided to discontinue the talks about modifying the transaction and desired to attempt to obtain regulatory approval of the transaction as currently structured. The Company announced that it continues to believe that the transaction cannot be accomplished on its present terms due to the KCC orders. In addition, the Company announced that it believes that the rate case order will result in a material adverse effect on the financial condition of the combined 23 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (8) Proposed Acquisition (Continued) companies and that there will be a failure of key conditions to consummation of the transaction if the KCC orders remain in effect. Western has advised the Company that it does not believe that the rate case order results in a material adverse effect. (9) New and Proposed Accounting Standards Decommissioning: The Staff of the Securities and Exchange Commission ("SEC") has questioned certain of the current accounting practices of the electric industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In February 2000, the Financial Accounting Standards Board ("FASB") issued an exposure draft regarding Accounting for Obligations Associated with the Retirement of Long-Lived Assets ("Exposure Draft"). The Exposure Draft requires the recognition of a liability for an asset retirement obligation at fair value. In addition, present value techniques used to calculate the liability must use a credit adjusted risk-free rate. Subsequent remeasures of the liability would be recognized using an allocation approach. The Company has not yet determined the impact of the Exposure Draft. 24 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS All references to the Company refer to Public Service Company of New Mexico or its proposed successor holding company PNM Resources, Inc. (see "Restructuring the Electric Utility Industry" below). The following is management's assessment of the Company's financial condition and the significant factors affecting the results of operations. This discussion should be read in conjunction with the Company's consolidated financial statements and Part I, Item 3. - Legal Proceedings. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. OVERVIEW The Company is an investor-owned integrated public utility primarily engaged in the generation, transmission, distribution and sale of electricity and in the transmission, distribution and sale of natural gas within the State of New Mexico. [In addition, in pursuing new business opportunities, the Company provides energy and utility related product offerings through its wholly-owned subsidiary, Avistar.] As it currently operates, the Company's principal business segments are Utility Operations, which include the Electric Product Offering ("Electric") and the Natural Gas Product Offering ("Gas"), and Generation and Trading Operations ("Generation and Trading"). Electric consists of two major business lines that include distribution and transmission. The transmission business line does not meet the definition of a segment for accounting purposes due to its immateriality, and for purposes of this discussion, it is combined with the distribution product offering. UTILITY OPERATIONS Electric The Company provides jurisdictional retail electric service to a large area of north central New Mexico, including the City of Albuquerque and the City of Santa Fe, and certain other areas of New Mexico. Retail sales revenues were $128.6 million and $125.4 million for the three months ended June 30, 2001 and 2000, respectively and $254.9 million and $246.8 million for the six months ended June 30, 2001 and 2000, respectively. The Company owns or leases 2,887 circuit miles of transmission lines, interconnected with other utilities in New Mexico and south and east into Texas, west into Arizona, and north into Colorado and Utah. Due to rapid load growth in recent years, most of the capacity on this transmission system is fully committed and there is no additional access available on a firm commitment basis. These factors, together with significant physical constraints in the system, limit the ability to wheel power into the Company's service area from outside the state. Gas The Company's Gas operations distribute natural gas to most of the major communities in New Mexico, including Albuquerque and Santa Fe. The Company's gas customer base includes both sales-service customers and 25 transportation-service customers. Sales-service customers purchase natural gas and receive transportation and delivery services from the Company for which the Company receives both cost-of-gas and cost-of-service revenues. Additionally, the Company makes occasional gas sales to off-system customers. Off-system sales deliveries generally occur at interstate pipeline interconnects with the Company's system. Transportation-service customers, who procure gas independently of the Company and contract with the Company for transportation and related services, provide the Company with cost-of-service revenues only. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. These contracts are generally sufficient to meet the Company peak-day demand. The following table shows gas throughput by customer class: GAS THROUGHPUT (Thousands of decatherms)
Three Months Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 ------------ ------------ ------------- ------------- Residential................................. 3,557 3,686 16,020 14,793 Commercial.................................. 1,466 1,370 5,691 4,861 Industrial.................................. 1,540 1,101 3,520 1,325 Transportation*............................. 15,223 10,663 24,401 19,674 Other....................................... 1,110 2,126 2,777 4,058 ------------ ------------ ------------- ------------- 22,896 18,946 52,409 44,711 ============ ============ ============= =============
The following table shows gas revenues by customer: GAS REVENUES (Thousands of dollars)
Three Months Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 ------------ ------------ ------------- ------------- Retail...................................... $44,802 $30,426 $166,396 $93,277 Commercial.................................. 12,881 8,189 49,675 24,804 Industrial.................................. 12,381 3,884 25,918 4,678 Transportation*............................. 6,411 2,947 10,413 6,931 Other....................................... 10,609 9,068 26,618 19,370 ------------ ------------ ------------- ------------- $ 87,084 $54,514 $279,020 149,060 ============ ============ ============= =============
*Customer-owned gas. 26 GENERATION AND TRADING OPERATIONS The Company's Generation and Trading Operations serve four principal markets. Sales to the Company's Utility Operations to cover jurisdictional electric demand and sales to firm-requirements wholesale customers, sometimes referred to collectively as "system" sales, comprise two of these markets. The third market consists of other contracted sales to third parties for which the Generation and Trading Operations commit to deliver a specified amount of capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of time. The fourth market consists of economy energy sales made on an hourly basis at fluctuating, spot-market rates. Sales to the third and fourth markets are sometimes referred to collectively as "off-system" sales. Off-system sales include the Company's energy trading activities. The following table shows sales by customer class: GENERATION AND TRADING SALES BY MARKET (Megawatt hours)
Three Months Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 -------------- ------------- -------------- ------------- Intersegment sales........................ 1,771,214 1,721,661 3,489,779 3,376,811 Firm-requirement wholesale................ 152,947 46,835 275,734 94,756 Other contracted off-system sales......... 1,604,223 1,471,743 3,505,484 3,514,741 Economy energy sales...................... 1,394,185 1,427,082 2,528,269 2,699,750 -------------- ------------- -------------- ------------- 4,922,569 4,667,321 9,799,266 9,686,058 ============== ============= ============== =============
The following table shows revenues by customer class: GENERATION AND TRADING REVENUES BY MARKET (Thousands of dollars)
Three Months Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 -------------- ------------- --------------- ------------- Intersegment revenues..................... $ 83,396 $ 78,869 $ 164,313 $154,692 Firm-requirement wholesale................ 4,234 1,890 7,363 3,625 Other contracted off-system revenues...... 243,000 65,697 440,891 128,504 Economy energy sales...................... 216,570 86,912 426,211 122,626 Other*.................................... (22,442) (11,457) (22,855) (11,238) -------------- ------------- --------------- ------------- $524,758 $221,911 $1,015,923 $398,208 ============== ============= =============== =============
*Includes mark-to-market gains/(losses). See footnote (4) in Notes to Consolidated Financial Statements. The Company has ownership interests in certain generating facilities located in New Mexico, including the San Juan Generating Station and the Four 27 Corners Power Plant, coal fired plants. In addition, the Company has ownership and leasehold interests in Palo Verde Nuclear Generating Station ("PVNGS") located in Arizona. These generation assets are used to supply retail and wholesale customers. The Company also owns Reeves Generating Station and Las Vegas Generating Station, gas and oil fired plants, that are used for reliability purposes or to generate electricity for the wholesale market during certain demand periods in the Generation and Trading Operations' wholesale power markets. As of June 30, 2001, the total net generation capacity of facilities owned or leased by the Company was 1,653 MW, including a 132 MW power purchase contract accounted for as an operating lease. In addition to its generation capacity, the Generation and Trading Operations purchases power in the open market. AVISTAR The Company's wholly-owned subsidiary, Avistar, was formed in August 1999 as a New Mexico corporation and is currently engaged in certain unregulated, non-utility business ventures. The PRC authorized the Company to invest $50 million in equity in Avistar and to enter into a reciprocal loan agreement for up to $30 million. The Company has currently invested $35 million in Avistar and has no amounts outstanding under the reciprocal loan agreement. PROPOSED ACQUISITION On November 9, 2000, the Company and Western Resources, Inc. ("Western Resources") announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources' electric utility operations in a tax-free, stock-for-stock transaction. Due to recent actions by the Kansas Corporation Commission ("KCC"), the Company believes the transaction cannot be accomplished under the terms of the present acquisition agreement if the orders remain in effect. (See "Other Issues Facing The Company- Proposed Acquisition of Western Resources Electric Operations" below). If the present transaction is completed, the new combined company will serve over one million retail electric customers and 435,000 retail gas customers in New Mexico and Kansas and will have generating capacity of more than 7,000 MW. The Company intends to proceed with plans to add generation capacity to serve Western United States wholesale markets. If completed, the transaction will also make the new company a leading energy supplier in the Western and Midwestern wholesale markets. 28 RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delay the original implementation dates by approximately five years, including the requirement for corporate separation of certain deregulated activities from activities regulated by the PRC. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. The amendments to the Restructuring Act require that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of the regulated and deregulated activities, by July 1, 2001. In addition, the amendments allow utilities to engage in unregulated power generation business activities until corporate separation is implemented. The Company believes that its ability to form a new holding company and expand generation assets in an unregulated environment will give it the flexibility it needs to pursue its strategic plan despite the delay in customer choice and corporate separation. The Company is unable to predict the form its restructuring will take under the delayed implementation of customer choice. The formulation of a restructuring plan will be dependent on future business conditions at the expected time customer choice is implemented (See Other Issues Facing The Company - Recovery of Certain Costs Under The Restructuring Act" below). In June 2000, shareholders approved the mandatory share exchange necessary to implement a holding company structure, with the holding company to be named Manzano Corporation. In April 2001, the Company's Board of Directors amended the articles of incorporation of the proposed holding company to rename the holding company "PNM Resources, Inc." (PNM Resources). In April 2001, the Company filed its application for the creation of a holding company. Hearings on the matter occurred in mid May. The PRC issued an order approving formation of a holding company on June 28, 2001. The order limits the Company's proposed utility subsidiary's ability to pay dividends to the parent holding company to annual current earnings determined on a rolling four quarter average and imposes certain regulatory requirements on the construction of merchant generation plants. The Company believes that certain conditions imposed by the PRC order are unnecessarily burdensome and could have an adverse effect on the Company's ability to execute its growth strategy. On July 27, 2001, the Company asked the PRC to reconsider certain conditions imposed by the order. The PRC has until August 16 to respond to the Company's request for rehearing. If the PRC does not act by then, the request is automatically denied. The Company is unable to predict the outcome of a rehearing if granted. If the result of the request for rehearing is unfavorable, the Company will consider filing an appeal to the New Mexico Supreme Court. COMPETITIVE STRATEGY The Restructuring Act, as amended, allows the Company and other utilities to build, operate, invest in or acquire new generating plants for merchant purposes in the interim with minimum regulatory approvals. These new 29 plants will be excluded from utility rates under the provisions of the bill. The cost of new unregulated utility generation resources will serve as a cap for ratemaking purposes, for the price of new resources needed to serve retail customers until customer choice and corporate restructuring is implemented. In addition, the New Mexico Legislature passed and the Governor signed, an amendment to the Public Utility Act requiring the PRC to act on siting applications for certain generating plants and transmission lines within six months. The PRC is allowed an additional ten months to act on transmission applications that are environmentally sensitive. The Company's Generation and Trading Operations have contributed significant earnings to the Company in recent years as a result of increased off-system sales including its energy trading activities. The Company plans to expand its wholesale energy trading functions which could include an expansion of its generation portfolio as well as expanding trading operations. The Company continuously evaluates its physical asset acquisition strategies to ensure an optimal mix of base-load generation, peaking generation and purchased power in its power portfolio. In addition to the continued energy trading activities, the Company will further focus on opportunities in the market place where excess capacity is disappearing and mid- to long-term market demands are growing. The Company's current business plan calls for increasing generating capacity and wholesale sales. The Company's ability to execute its growth plan may be impacted by the holding company order issued by the PRC on June 28, 2001 (see "Restructuring the Electric Utility Industry" above). The Company intends to spend approximately $800 million over the next five years to grow its generation portfolio. Such growth will be dependent upon the Company's ability to generate funds for the Company's expansion. The Company currently has $233 million of available cash as well as adequate borrowing capacity to fund the expansion program. There can be no assurance that investments in new unregulated generation facilities will be successful or, if unsuccessful, that they will not have a direct or indirect adverse effect on the Company. At the Federal level, there have been a number of proposals on electric restructuring being considered with no concrete timing for definitive actions. None of these proposals have been acted upon by Congress. Issues such as stranded cost recovery, market power, utility regulation reform, the role of states, subsidies, consumer protections and environmental concerns are expected to be considered in the current Congressional session. In addition, the FERC has stated that if Congress mandates electric retail access, it should leave the details of the program to the states with the FERC having the authority to order the necessary transmission access for the delivery of power for the states' retail access programs. Recent federal actions have focused on the energy crisis in California with bills being introduced to require caps on wholesale prices. In addition, the Senate Banking Committee has voted 19-1 to repeal the Public Utility Holding Company Act. Although it is unable to predict the ultimate outcome of retail competition in New Mexico, the Company has been and will continue to be active at both the state and Federal levels in the public policy debates on the restructuring of the electric utility industry. The Company will continue to work with customers, regulators, legislators and other interested parties to find solutions that bring benefits from competition while recognizing the importance of reimbursing utilities for past commitments. 30 RESULTS OF OPERATIONS The following discussion is based on the financial information presented in Footnote 1 of the Consolidated Financial Statements - Nature of Business and Segment Information. The table below sets forth the operating results as percentages of total operating revenues for each business segment. Three Months Ended June 30, 2001 Compared to Three Months Ended June 30, 2000 Three Months Ended June 30, 2001
Utility ------------------------------------------- Generation Electric Gas and Trading --------------------- -------------------- --------------------- Operating revenues: External customers................... $136,368 99.87% $ 87,084 100.00% $441,362 84.11% Intersegment revenues................ 177 0.13 - 0.00 83,396 15.89 ---------- --------- ---------- -------- ---------- ---------- Total revenues....................... 136,545 100.00 87,084 100.00 524,758 100.00 ---------- --------- ---------- -------- ---------- ---------- Cost of energy sold.................... 1,252 0.92 57,745 66.31 374,844 71.43 Intersegment purchases................. 83,396 61.08 - 0.00 177 0.03 ---------- --------- ---------- -------- ---------- ---------- Total fuel costs..................... 84,648 61.99 57,745 66.31 375,021 71.47 ---------- --------- ---------- -------- ---------- ---------- Gross margin........................... 51,897 38.01 29,339 33.69 149,737 28.53 ---------- --------- ---------- -------- ---------- ---------- Administrative and other costs......... 10,812 7.92 11,488 13.19 6,700 1.28 Energy production costs................ 193 0.14 382 0.44 37,304 7.11 Depreciation and amortization.......... 8,066 5.91 5,333 6.12 10,521 2.00 Transmission and distribution costs.... 8,334 6.10 6,647 7.63 100 0.02 Taxes other than income taxes.......... 3,133 2.29 2,056 2.36 2,322 0.44 Income taxes........................... 6,761 4.95 189 0.22 33,134 6.31 ---------- --------- ---------- -------- ---------- ---------- Total non-fuel operating expenses.... 37,299 27.32 26,095 29.97 90,081 17.17 ---------- --------- ---------- -------- ---------- ---------- Operating income....................... $14,598 10.69% $ 3,244 3.73% $59,656 11.37% ---------- --------- ---------- -------- ---------- ----------
Three Months Ended June 30, 2000
Utility --------------------------------------------- Generation Electric Gas and Trading ----------------------- --------------------- -------------------- Operating revenues: External customers................... $130,142 99.86% $54,514 100.00% $143,042 64.46% Intersegment revenues................ 177 0.14 - 0.00 78,869 35.54 ----------- ---------- ---------- --------- ---------- --------- Total revenues....................... 130,319 100.00 54,514 100.00 221,911 100.00 ----------- ---------- ---------- --------- ---------- --------- Cost of energy sold.................... 1,132 0.87 30,097 55.21 149,165 67.22 Intersegment purchases................. 78,869 60.52 - 0.00 177 0.08 ----------- ---------- ---------- --------- ---------- --------- Total fuel costs..................... 80,001 61.39 30,097 55.21 149,342 67.30 ----------- ---------- ---------- --------- ---------- --------- Gross margin........................... 50,318 38.61 24,417 44.79 72,569 32.70 ----------- ---------- ---------- --------- ---------- --------- Administrative and other costs......... 8,427 6.47 9,393 17.23 4,399 1.98 Energy production costs................ 212 0.16 421 0.77 35,272 15.89 Depreciation and amortization.......... 7,720 5.92 4,515 8.28 10,391 4.68 Transmission and distribution costs.... 8,003 6.14 6,777 12.43 16 0.01 Taxes other than income taxes.......... 3,165 2.43 1,832 3.36 2,567 1.16 Income taxes........................... 7,186 5.51 (482) (0.88) 3,330 1.50 ----------- ---------- ---------- --------- ---------- --------- Total non-fuel operating expenses.... 34,713 26.64 22,456 41.19 55,975 25.22 ----------- ---------- ---------- --------- ---------- --------- Operating income....................... $15,605 11.97% $ 1,961 3.60% $ 16,594 7.48% ----------- ---------- ---------- --------- ---------- ---------
31 Three Months Ended June 30, 2001 Compared to Three Months Ended June 30, 2000 UTILITY OPERATIONS Electric - Operating revenues increased $6.2 million (4.8%) for the period to $136.5 million. Retail electricity delivery grew 2.9% to 1.77 million MWh in 2001 compared to 1.72 million MWh delivered in the prior year period, resulting in increased revenues of $3.3 million period-over-period. This volume increase was the result of both a weather-driven increase in consumption and normal load growth. In addition, transmission wheeling revenues increased $3.4 million as a result of additional capacity sales. These sales were generated by high demand to transmit electricity to California and other states. The gross margin, or operating revenues minus cost of energy sold, increased $1.6 million but declined slightly as a percentage of revenues. This dollar increase reflects the increased energy sales, partially offset by an increase in intersegment transfer pricing. Gross margin as a percentage of revenues declined from 38.6% to 38.0%. The decline in gross margin percentage is primarily a result of the increase in intersegment transfer pricing. The Company's Generation and Trading Operations exclusively provide power to Electric. Intersegment purchases from the Generation and Trading Operations are priced using internally developed transfer pricing and are not based on market rates. Customer rates for electric service are set by the PRC based on the recovery of the cost of power production and a rate of return that includes certain generation assets that are part of Generation and Trading Operations, among other things. Administrative and general costs increased $2.4 million (28.3%) for the period. This increase is primarily due to increased pension and benefits expense resulting from lower than expected investment returns on related plan assets. As a percentage of revenues, administrative and other costs increased to 7.9% from 6.5% for the three months ended June 30, 2001 and 2000, respectively, as a result of the increased pension and benefits costs. Gas - Operating revenues increased $32.6 million (59.7%) for the period to $87.1 million. This increase was driven by a 32.1% increase in the average rate charge per decatherm due to continued high market prices for natural gas in the second quarter of 2001 resulting from increased market demand, a 20.9% volume increase and a gas rate increase which became effective October 30, 2000. Residential and commercial customers volume decreased slightly (0.7%). Customer volume, other than residential and commercial, increased 28.7%. This growth was primarily attributed to transportation and industrial customers such as the Company's Generation and Trading Operations whose increased demand was driven by the strong power market prevailing in the Western United States during the second quarter of 2001. In the second quarter of 2001, the Company's Generation and Trading Operations began procuring its gas supply independent of the Company and contracting with the Utility Operations for transportation services only. The Company does not earn cost of service revenues on transportation customers. The gross margin, or operating revenues minus cost of energy sold, increased $4.9 million (20.2%). This increase is due to the rate increase, 32 higher distribution volumes on which the Company earns cost of service revenues and higher off-system transportation volumes. The Company purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, the increase in gas prices driving increased cost of sales revenues does not have an impact on the Company's gross margin or earnings. Administrative and general costs increased $2.1 million (22.3%). This increase is due to increased pension and benefits expense and customer service expense for increased collection activities, partially offset by decreased bad debt costs due to stabilization of the Company's new billing system. Depreciation and amortization increased $0.8 million (18.1%) for the period due to a higher depreciable plant base. GENERATION AND TRADING OPERATIONS Operating revenues grew $302.8 million (136.5%) for the period to $524.8 million. This increase in wholesale electricity sales reflects prevailing strong regional wholesale electric prices. The Company delivered wholesale (bulk) power of 3.2 million MWh of electricity this period compared to 2.9 million MWh delivered in the prior period, an increase of 7.0%. The MWh increase is attributable to increased wholesale trading activity during the period. The strong wholesale electric prices were caused by limited power generation capacity, increased natural gas prices and the power supply/demand imbalance in the Western United States. These factors contributed to unusually high wholesale prices in the second half of 2000 and most of 2001, to date, which the Company does not believe to be sustainable in the long-term but may continue in 2002. In fact, the wholesale electric and natural gas markets experienced falling price levels at the end of the second quarter of 2001. This trend has continued in the third quarter of 2001. In addition, on June 19, 2001, the Federal Energy Regulatory Commission ("FERC") mandated a price mitigation plan. Since the end of the second quarter, prices have declined significantly, and liquidity in the market place - the opportunity to buy/resell power - has also declined as trading activity has slowed (see Other Issues Facing the Company - Western United States Wholesale Power Market). If these trends continue, the Company expects operating revenues from wholesale trading activities to decline from levels achieved in the last half of 2000 and first half of 2001(see Future Expectations). The majority of the wholesale sales are from power purchased for resale. Exposure to adverse market moves is limited through an asset backed strategy, whereby the Company's aggregate net open position is covered by its generation resources, primarily generation which has been excluded from retail rates. This strategy, along with the Company's credit policies, limits the Company's wholesale sales in a volatile market. Wholesale revenues from third-party customers increased from $143.0 million to $441.4 million, a 208.6% increase. The increase was largely price driven. The gross margin, or operating revenues minus cost of energy sold, increased $77.2 million (106.3%). Gross margin as a percentage of revenues decreased from 32.7% to 28.5% reflecting increased prices for purchased power for resale. Higher margins were partially offset by unrealized mark-to-market losses of $27.3 million which the Company recognized relating to its power trading contracts (see Note 4 of the Notes to Consolidated Financial 33 Statements). This mark-to-market adjustment is due to the significant decline in electric prices at the end of the second quarter. In addition, as a result of the falling prices at the end of the second quarter, the Company recorded a $6.5 million reduction in its allowances for market price volatility and credit risk in the wholesale power market (see Other Issues Facing The Company - Western United States Wholesale Power Market). These items were recorded as revenue adjustments. Administrative and general costs increased $2.3 million (52.3%) for the period. This increase is primarily due to increased pension and benefits expense. As a percentage of revenues, administrative and other costs decreased to 1.3% from 2.0% for the three months ended June 30, 2001 and 2000, respectively as a result of increased revenues. Energy production costs increased $2.0 million (5.8%) for the period. The increase is due to higher maintenance costs in 2000 resulting from scheduled and unscheduled outages at San Juan, Palo Verde and Four Corners and increased generation at Reeves, one of the Company's gas generation facilities, which has a higher cost of production than its coal and nuclear facilities. As a percentage of revenues, energy production costs decreased from 15.9% to 7.1%. The decrease is primarily due to the significant increase in energy revenues. UNREGULATED BUSINESSES Avistar continued to experience lower business volumes resulting from slow developing markets associated with its new product offerings. Operating losses for Avistar increased from $0.8 million in the prior year period to $1.6 million in the current year period primarily due to increased costs related to the shut down of certain operations. CONSOLIDATED Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, decreased $2.7 million for the period. This decrease was due to lower legal costs associated with routine business operations and lower reorganizational costs incurred in 2000 that did not occur in 2001 due to the legislative mandated delay in separating utility operations under the Restructuring Act (see "Restructuring The Electric Utility Industry"). This decrease is partially offset by an increase in bonus accruals reflecting the Company's earnings profile for 2001. Other income and deductions, net of taxes, decreased $21.3 million for the period to a loss of $14.6 million primarily due to the write-off of $13.0 million (pre-tax) of non-recoverable coal mine decommissioning costs previously established as a regulatory asset. As a result of the Company's evaluation of its regulatory strategy in light of the holding company filing in May 2001, management determined that it would not seek recovery at the Federal level of a portion of its previously established regulatory cost asset. The remaining portion of costs associated with coal mine decommissioning that are attributed to local jurisdictional customers will be sought in future rate cases. As a result, the Company will continue to evaluate the recoverability of such costs as the rate making process occurs. In addition, the Company will identify its stranded costs as separation nears (See Other Issues Facing the Company - Recovery of Certain Costs Under the Restructuring Act). The current period also had a donation of $5.0 million (pre-tax) to the PNM Foundation, unrecoverable costs of $2.3 million (pre-tax) related to a failed transmission line, increased mark-to-market losses on the PVNGS decommissioning trust assets of $1.0 million (pre-tax) (see Note 4 to the Consolidated Financial Statements) and $3.6 million (pre-tax) of costs related to the Company's proposed acquisition of Western Resources' electric utility operations. If the transaction continues to move forward, the Company expects to continue to incur acquisition related costs in 2001 and beyond (see "Other Issues Facing the Company - Proposed Acquisition of Western Resources Electric Operations" below). 34 The Company's consolidated income tax expense was $20.9 million in the three months ended June 30, 2001, an increase of $11.2 million for the period. The Company's income tax effective rate for the three months ended June 30, 2001 was 29.68%. Included in the Company's 2001 taxable income are certain non-deductible costs related to the Company's acquisition of Western Resources' electric utility operations. In addition, income tax expense includes the reversal of $6.6 million of allowances taken against certain income tax related regulatory assets in 2000 as a result of the Company's evaluation of its regulatory strategy in light of the holding company filing in May 2001. In 2000, management believed these income tax related regulatory assets would not be recoverable based on the probable financial outcome of industry restructuring in New Mexico. The charge to earnings in 2000, related to the write-off of these assets, reflected management's view of the probable financial outcome of industry restructuring in New Mexico based on discussions between the Company and the PRC staff at that time. Currently, management fully expects to recover these costs in future rate cases, a situation that was not possible prior to the delay in open access in New Mexico. Excluding the impact of these items, the Company's effective tax rate was 38.8%. The Company's effective tax rate for the three months ended June 30, 2000 was 35.0%. The increase in the rate was primarily due to an increase in the depreciation of flow-through items. The Company's net earnings for the three months ended June 30, 2001 were $49.6 million, a 175.8% increase. Excluding the write-off of coal mine decommissioning costs, the donation to the PNM Foundation and the Western Resources' acquisition costs and the related impact on the effective tax rate ("2001 Special Items"), the Company's net earnings were $62.8 million. Net earnings for the three months ended June 30, 2000 were $18.0 million. Net earnings from continuing operations excluding the 2001 Special Items increased from $18.0 million in 2000 to $62.8 million in 2001. Earnings per share on a diluted basis were $1.57 (excluding the 2001 Special Items) for the three months ended June 30, 2001 compared to $0.45 for the three months ended June 30, 2000. Diluted weighted average shares outstanding were 40.0 million and 39.6 million in 2001 and 2000, respectively. The increase reflects the increase in the common stock share price, which had a dilutive effect on options outstanding in 2001, partially offset by the common stock repurchase program in 2000. Net earnings per share from continuing operations primarily increased due to increased operating income from the Company's Generation and Trading Operations. 35 Six Months Ended June 30, 2000 Compared to Six Months Ended June 30, 2000 The table below sets forth the operating results as percentages of total operating revenues for each business segment. Six Months Ended June 30, 2001
Utility ----------------------------------------- Generation Electric Gas and Trading -------------------- -------------------- ---------------------- Operating revenues: External customers..................... $270,714 99.87% $279,020 100.00% $851,610 83.83% Intersegment revenues.................. 353 0.13 - 0.00 164,313 16.17 -------- ---------- --------- --------- ----------- ---------- Total revenues......................... 271,067 100.00 279,020 100.00 1,015,923 100.00 -------- ---------- --------- --------- ----------- ---------- Cost of energy sold...................... 2,812 1.04 206,217 73.91 721,910 71.06 Intersegment purchases................... 164,313 60.62 - 0.00 353 0.03 -------- ---------- --------- --------- ----------- ---------- Total fuel costs....................... 167,125 61.65 206,217 73.91 722,263 71.09 -------- ---------- --------- --------- ----------- ---------- Gross margin............................. 103,942 38.35 72,803 26.09 293,660 28.91 -------- ---------- --------- --------- ----------- ---------- Administrative and other costs........... 20,546 7.58 23,688 8.49 11,660 1.15 Energy production costs.................. 503 0.19 812 0.29 71,588 7.05 Depreciation and amortization............ 16,091 5.94 10,623 3.81 21,416 2.11 Transmission and distribution costs...... 16,441 6.07 13,703 4.91 213 0.02 Taxes other than income taxes............ 5,660 2.09 3,652 1.31 4,243 0.42 Income taxes............................. 14,311 5.28 5,694 2.04 65,856 6.48 -------- ---------- --------- --------- ----------- ---------- Total non-fuel operating expenses...... 73,552 27.13 58,172 20.85 174,976 17.22 -------- ---------- --------- --------- ----------- ---------- Operating income......................... $30,390 11.21% $14,631 5.24% $118,684 11.68% -------- ---------- --------- --------- ----------- ----------
Six Months Ended June 30, 2000
Utility ------------------------------------------- Generation Electric Gas and Trading -------------------- ---------------------- ---------------------- Operating revenues: External customers..................... $256,064 99.86% $ 149,060 100.00% $243,516 61.15% Intersegment revenues.................. 353 0.14 - 0.00 154,692 38.85 ---------- --------- ---------- ---------- ----------- ---------- Total revenues......................... 256,417 100.00 149,060 100.00 398,208 100.00 ---------- --------- ---------- ---------- ----------- ---------- Cost of energy sold...................... 2,265 0.88 87,930 58.99 257,922 64.77 Intersegment purchases................... 154,692 60.33 - 0.00 353 0.09 ---------- --------- ---------- ---------- ----------- ---------- Total fuel costs....................... 156,957 61.21 87,930 58.99 258,275 64.86 ---------- --------- ---------- ---------- ----------- ---------- Gross margin............................. 99,460 38.79 61,130 41.01 139,933 35.14 ---------- --------- ---------- ---------- ----------- ---------- Administrative and other costs........... 17,502 6.83 19,306 12.95 8,694 2.18 Energy production costs.................. 628 0.24 789 0.53 70,131 17.61 Depreciation and amortization............ 16,047 6.26 9,881 6.63 20,703 5.20 Transmission and distribution costs...... 15,866 6.19 14,178 9.51 24 0.01 Taxes other than income taxes............ 6,495 2.53 3,808 2.55 5,334 1.34 Income taxes............................. 13,285 5.18 3,089 2.07 4,758 1.19 ---------- --------- ---------- ---------- ----------- ---------- Total non-fuel operating expenses...... 69,823 27.23 51,051 34.25 109,644 27.53 ---------- --------- ---------- ---------- ---------- ---------- Operating income......................... $29,637 11.56% $ 10,079 6.76% $ 30,289 7.61% ---------- --------- ---------- ---------- ----------- ----------
36 Six Months Ended June 30, 2001 Compared to Six Months Ended June 30, 2000 UTILITY OPERATIONS Electric - Operating revenues increased $14.7 million (5.7%) for the period to $271.1 million. Retail electricity delivery grew 3.4% to 3.49 million MWh in 2001 compared to 3.38 million MWh delivered in the prior year period, resulting in increased revenues $8.1 million period-over-period. This volume increase was the result of both a weather-driven increase in consumption and load growth. In addition, transmission wheeling revenues increased $6.1 million as a result of additional capacity sales and other revenues increased $1.6 million primarily for new property leasing for telecommunication systems. The gross margin, or operating revenues minus cost of energy sold, increased $4.5 million but declined slightly as a percentage of revenues. This dollar increase reflects the increased energy sales transmission wheeling revenues and the telecommunication property leasing, partially offset by an increase in intersegment transfer pricing. Gross margin as a percentage of revenues declined from 38.8% to 38.4%. The decline in gross margin percentage is primarily a result of the increase in intersegment transfer pricing. The Company's Generation and Trading Operations exclusively provide power to Electric. Intersegment purchases from the Generation and Trading Operations are priced using internally developed transfer pricing and are not based on market rates. Customer rates for electric service are set by the PRC based on the recovery of the cost of power production and a rate of return that includes certain generation assets that are part of Generation and Trading Operations, among other things. Administrative and general costs increased $3.0 million (17.4%) for the period. This increase is primarily due to increased pension and benefits expense resulting primarily from lower than expected investment returns on related plan assets. As a percentage of revenues, administrative and other costs increased to 7.6% from 6.8% for the six months ended June 30, 2001 and 2000, respectively, as a result of the increased pension and benefits costs. Transmission and distribution costs increased $0.6 million (3.6%) primarily due to increased transmission maintenance for reliability purposes. Transmission and distribution costs as a percentage of revenues were 6.1% for the six months ended June 30, 2001 and 2000, respectively. Taxes other than income decreased $0.8 million (12.9%) due to higher tax liabilities in the prior year period as a result of audits by certain tax authorities. Taxes other than income as a percentage of revenues decreased to 2.1% from 2.5%. Gas - Operating revenues increased $130.0 million (87.2%) for the period to $279.0 million. This increase was driven by a 61.4% increase in the average rate charge per decatherm due to prevailing high wholesale gas prices in 2001 resulting from increased market demand, a 17.2% volume increase and a gas rate increase, which became effective October 30, 2000. Residential and 37 commercial customers volume increased 10.5% due to a colder winter during 2001. Customer volume, other than residential and commercial, increased 22.5%. This growth was primarily attributed to transportation and industrial customers such as the Company's Generation and Trading Operations whose increased demand was driven by the strong power market prevailing in the Western United States during 2001. In the second quarter of 2001, the Company's Generation and Trading Operations began procuring its gas supply independent of the Company and contracting with the Utility Operations for transportation services only. The Company does not earn cost of service revenues on transportation customers. The gross margin, or operating revenues minus cost of energy sold, increased $11.7 million (19.1%). This increase is due to the rate increase, higher distribution volumes on which the Company earns cost of service revenues and higher off-system transportation volumes. The Company purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, the increase in gas prices driving increased cost of sales revenues does not have an impact on the Company's gross margin or earnings. Administrative and general costs increased $4.4 million (22.7%). This increase is due largely to increased pension and benefits expense as well as increased bad debt costs recognized in anticipation of a higher than normal delinquency rate driven by the significantly higher natural gas prices experienced in the 2000-2001 heating season. This trend is similar to historic collection trends and patterns associated with past natural gas price spikes. Depreciation and amortization increased $0.7 million (7.5%) for the period due to a higher depreciable plant base. Transmission and distribution costs decreased $0.5 million (3.4%) primarily due to increased capital activity and unfilled vacancies. GENERATION AND TRADING OPERATIONS Operating revenues grew $617.7 million (155.1%) for the period to $1.0 billion. This increase in wholesale electricity sales reflects continued strong regional wholesale electric prices. The Company delivered wholesale (bulk) power of 6.3 million MWh of electricity this period, which remained constant as compared to the prior period. The strong wholesale electric prices were caused by limited power generation capacity, increased natural gas prices and the power supply/demand imbalance in the Western United States. These factors contributed to unusually high wholesale prices in the second half of 2000 and most of 2001, which the Company does not believe to be sustainable in the long-term, but may continue in 2002. In fact, the market experienced falling price levels at the end of the second quarter of 2001. This trend has continued in the third quarter of 2001. In addition, on June 19, 2001, the Federal Energy Regulatory Commission ("FERC") mandated a price mitigation plan. Since the end of the second quarter, wholesale electricity prices have declined significantly, and liquidity - the opportunity to buy and resell power - in the market place has also declined as trading activity has slowed (see Other Issues Facing the Company - Western United States Wholesale Power Market). If these trends continue, the Company expects operating revenues to decline in subsequent quarters (see - Future Expectations). The majority of the wholesale sales are from power purchased for resale. Exposure to adverse market moves is limited through an asset backed strategy, whereby the Company's aggregate net open position is covered by its generation resources, primarily generation which has been excluded from retail rates. This strategy, along with the Company's credit policies, limits the Company's wholesale sales in a volatile market. Wholesale revenues from third-party customers increased from $243.5 million to $851.6 million, a 249.7% increase. The increase was largely price driven. 38 The gross margin, or operating revenues minus cost of energy sold, increased $153.7 million (109.9%). Gross margin as a percentage of revenues decreased from 35.1% to 28.9% reflecting increased prices for purchased power for resale. Higher margins were partially offset by unrealized mark-to-market losses of $26.2 million which the Company recognized relating to its power trading contracts (see Note 4 of the Notes to Consolidated Financial Statements). This mark-to-market adjustment is due to the significant decline in electric prices at the end of the second quarter. In addition, the Company recorded $6.7 million of allowances for market and credit risk in the wholesale power market (see Other Issues Facing The Company - Western United States Wholesale Power Market). These items were recorded as revenue adjustments. Administrative and general costs increased $3.0 million (34.1%) for the period. This increase is primarily due to increased pension and benefits expense. As a percentage of revenues, administrative and other costs decreased to 1.2% from 2.2% for the six months ended June 30, 2001 and 2000, respectively as a result of increased wholesale revenues. Energy production costs increased $1.5 million (2.1%) for the year. The increase is due to higher maintenance costs in 2000 resulting from scheduled and unscheduled outages at San Juan, Palo Verde and Four Corners and increased generation at Reeves, one of the Company's gas generation facility, which has a higher cost of production than its coal and nuclear facilities. As a percentage of revenues, energy production costs decreased from 17.6% to 7.1%. The decrease is primarily due to the significant increase in wholesale revenues. Depreciation and amortization increased $0.7 million (3.4%) for the period due to a higher depreciable plant base. Depreciation and amortization as a percentage of revenues decreased from 5.2% to 2.1% due to the increase in wholesale revenues. Taxes other than income decreased $1.1 million (20.5%) due to higher tax liabilities in the prior year period as a result of audits by certain tax authorities. Taxes other than income as a percentage of revenues decreased from 1.3% to 0.4% as a result of the increase in wholesale revenues. UNREGULATED BUSINESSES Avistar continued to experience lower business volumes resulting from slow developing markets associated with its product offerings. Operating losses for Avistar increased from $2.0 million in the prior year period to $2.8 million in the current year period primarily due to increased costs related to the shut down of certain operations. CONSOLIDATED Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, increased $1.2 million for the period. This increase was due to additional bonus expense as a result of increased earnings, partially offset by lower legal costs associated with routine business operations and reorganizational costs incurred in 2000 that did not occur in 2000 due to the legislative mandated delay in separating utility operations under the Restructuring Act (see "Restructuring The Electric Utility Industry"). 39 Other income and deductions, net of taxes, decreased $26.2 million for the period to a loss of $12.0 million primarily due to the write-off of $13.0 million (pre-tax) of non-recoverable coal mine decommissioning costs previously established as a regulatory asset. As a result of the Company's evaluation of its regulatory strategy in light of the holding company filing in May 2001, management determined that it would not seek recovery of a portion of its previously established stranded cost asset. The remaining portion of costs associated with coal mine decommissioning that are attributed to local jurisdictional customers will be sought in future rate cases. As a result, the Company will continue to evaluate the recoverability of such cost as the rate making process occurs. In addition, the Company will identify its stranded cost as separation nears. The current year also had valuation losses of $8.3 million (pre-tax) related to investments in two energy-related technology companies, a donation of $5.0 million (pre-tax) to the PNM Foundation, unrecoverable costs of $2.3 million (pre-tax) related to a failed transmission line, mark-to-market losses on the PVNGS decommissioning trust assets and the Company's hedge of certain non-qualified retirement plan trust assets of $1.8 million (pre-tax) compared to market-to-market gains of $3.7 million (pre-tax) in the prior year (see Note 4 to the Consolidated Financial Statements) and $4.6 million (pre-tax) of costs related to the Company's proposed acquisition of Western Resources' electric utility operations. If the transaction continues to move forward, the Company expects to continue to incur acquisition related costs in 2001 and beyond (see "Other Issues Facing the Company - Proposed Acquisition of Western Resources Electric Operations" below). The Company's consolidated income tax expense was $63.6 million in the six months ended June 30, 2001, an increase of $41.2 million for the period. The Company's income tax effective rate for the six months ended June 30, 2001 was 35.97%. Included in the Company's 2001 taxable income are certain non-deductible costs related to the Company's acquisition of Western Resources' electric utility operations and the reversal of $6.6 million of allowances taken against certain income tax related regulatory assets in 2000 as a result of the Company's evaluation of its regulatory strategy in light of the holding company filing in May 2001. In 2000, management believed these income tax related regulatory assets would not be recoverable based on the probable financial outcome of industry restructuring in New Mexico. The charge to earnings in 2000, related to these assets, reflected management's view of the probable financial outcome of industry restructuring in New Mexico, based on discussions occurring between the Company and the PRC staff at that time. Currently, management fully expects to recover these costs in future rate cases. Excluding the impact of these items, the Company's effective tax rate was 38.9%. The Company's effective tax rate for the three months ended June 30, 2000 was 36.0%. The increase in the rate was primarily due to an increase in the depreciation of flow-through items. The Company's net earnings for the six months ended June 30, 2001 were $113.1 million, a 183.3% increase. Excluding the write-off of coal mine decommissioning costs, the donation to the PNM Foundation and the Western Resources' acquisition costs and the related impact on the effective tax rate ("2001 Special Items"), the Company's net earnings were $128.2 million. Net earnings for the six months ended June 30, 2000 were $39.9 million. Net earnings from continuing operations excluding the 2001 Special Items increased from $39.9 million in 2000 to $128.2 million in 2001. Earnings per share on a diluted basis were $3.21 (excluding the 2001 Special Items) for the six months ended June 30, 2001 compared to $1.00 for the six months ended June 30, 2000. Diluted weighted average shares outstanding were 40 39.8 million in 2001 and 2000. This reflects the increase in the common stock share price, which had a dilutive effect on options outstanding in 2001, offset by the common stock repurchase program in 2000. Net earnings per share from continuing operations primarily increased due to the increased operating income from the Company's Generation and Trading Operations. FUTURE EXPECTATIONS On July 18, 2001, the Company announced that it expects full year 2001 earnings to be between $4.25 and $4.50 per share. While forecasting a substantial increase in earnings for 2001, management does not believe those gains are sustainable over the longer term. As conservation measures take effect in California and throughout the west, and as new generation comes on-line over the next two to three years, management expects that prices will stabilize at somewhat lower levels. In addition, on June 19, 2001, the FERC mandated its price mitigation plan. Prices have gone down significantly and liquidity in the market place has also declined as trading activity has slowed. Since a reduced pricing environment is likely to have a negative impact on the funding new generation, the Company would expect that forward prices would again trend upwards in future periods. Looking at the forward prices for power and natural gas and the Company's market positioning and base earnings ability, and assuming the FERC price caps are not decreased further and are lifted as scheduled, management believes that its earnings are sustainable at around $3.50 a share. Currently high wholesale prices have the potential to raise earnings substantially above that level in the near term but management believes that earnings at these higher levels are not sustainable over the long run. As the Company adds new generation resources, it is expected that earnings will trend upwards, although at a rate less than the 10 percent annual growth rate previously targeted by management due to the higher base earnings the Company has forecasted. The Company's strategic plan to add generation resources will provide electric wholesale volume growth beginning in 2002 and in the later years of the forecast. These expectations are all stand-alone forecasts and do not take into account any impact of the proposed acquisition of Western Resources. Management's revised expectations are based on its current view of the wholesale power market. Management's previous expectations with regard to the Company's utility operations and non-fuel operating and maintenance expenses remain largely unchanged. Management's expectations for 2001 assume retail sales growth will continue at rates comparable to what was experienced in 2000 and the full realization of the favorable outcome of the two gas rate cases settled in August of 2000. Expenses are expected to increase due to inflation, the overall impact of the decline in the investment marketplace of pension and employee benefit plans, growth initiatives and regulatory filing costs. These earnings estimates do not include any costs related to the Company's acquisition of the electric utility assets of Western Resources. The significant capital additions in 2000 are expected to result in increased depreciation and amortization expense in 2001. In addition, because of initiatives undertaken in 2000, it is expected that reduced losses in the non-regulated businesses will contribute to net earnings. 41 This discussion of future expectations is forward looking information within the meaning of Section 21E of the Securities Exchange Act of 1934. The achievement of expected results is dependent upon the assumptions described in the preceding discussion, and is qualified in its entirety by the Private Securities Litigation Reform Act of 1995 disclosure - (see "Disclosure Regarding Forward Looking Statements" below) - and the factors described within the disclosure which could cause the Company's actual financial results to differ materially from the expected results enumerated above. LIQUIDITY AND CAPITAL RESOURCES At June 30, 2001, the Company had working capital of $178.0 million including cash and cash equivalents of $233.3 million. This is an increase in working capital of $30.2 million from December 31, 2000. This increase primarily reflects increased cash receipts related to the Company's activity in the wholesale power market. Cash generated from operating activities in the six months ended June 30, 2001 was $257.5 million, an increase of $160.6 million from 2000. This increase was primarily the result of increased profitability. In addition, the Company did not make the first quarter estimated federal income tax payment because of an automatic extension granted by the IRS to taxpayers in several counties in New Mexico as a result of wildfires in 2000. This cash increase was partially offset by an increase in the Company's receivables due to increased wholesale electricity sales, net of a decrease in utility customer accounts receivable primarily as a result of seasonal volume declines. Improved operating cash flows have driven the Company's cash balance up to $233.3 million from $84.1 million at year end 2000. Cash used for investing activities was $113.0 million in 2001 compared to $65.0 million in 2000. This increased spending reflects combustion turbine progress payments of $37.3 million and $7.5 million related to the acquisition of certain transmission assets. Cash used for financing activities was $18.9 million was primarily used to fund dividend requirements. This compared to $68.2 million used in 2000. This decrease reflects the 2000 repurchase of $34.7 million of senior unsecured notes at a cost of $32.8 million and common stock repurchases in 2000 (see "Stock Repurchase" below). Capital Requirements Total capital requirements include construction expenditures as well as other major capital requirements and cash dividend requirements for both common and preferred stock. The main focus of the Company's construction program is upgrading generation systems, upgrading and expanding the electric and gas transmission and distribution systems and purchasing nuclear fuel. In addition, the Company anticipates significant expenditures to expand its generation capabilities. Projections for total capital requirements and construction expenditures for 2001 are $370 million and $353 million, respectively. Such projections for the years 2001 through 2005 are $1.52 billion and $1.45 billion, respectively. These estimates are under continuing review and subject to on-going adjustment (see "Competitive Strategy" above). The Company's construction expenditures for 2001 were entirely funded through cash generated from operations. The Company currently anticipates that internal cash generation and current debt capacity will be sufficient to meet 42 capital requirements for the years 2001 through 2005. To cover the difference in the amounts and timing of cash generation and cash requirements, the Company intends to use short-term borrowings under its liquidity arrangements. Liquidity At August 1, 2001, the Company had $170 million of available liquidity arrangements, consisting of $150 million from a senior unsecured revolving credit facility ("Credit Facility"), and $20 million in local lines of credit. The Credit Facility will expire in March 2003. There were no outstanding borrowings as of August 1, 2001. The Company's ability to finance its construction program at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, results of operations, credit ratings, regulatory approvals and financial market conditions. Financing flexibility is enhanced by providing a high percentage of total capital requirements from internal sources and having the ability, if necessary, to issue long-term securities, and to obtain short-term credit. In connection with the Company's announcement of its proposed acquisition of Western Resources' electric utility operations, Standard and Poors ("S&P"), Moody's Investor Services ("Moody's") and Fitch IBCA, Duff & Phelps ("Fitch") have placed the Company's securities ratings on negative credit watch pending review of the transaction. The Company is committed to maintaining its investment grade. S&P currently rates the Company's senior unsecured notes ("SUNs") and its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its preferred stock "BB". Moody's rates the Company's SUNs and senior unsecured pollution control revenue bonds "Baa3"; and preferred stock "ba1". The EIP senior secured debt are also rated "Ba1". Fitch rates the Company's SUNs and senior unsecured pollution control revenue bonds "BBB-," the Company's EIP lease obligation "BB+" and the Company's preferred stock "BB-." Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it may be subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating. Covenants in the Company's Palo Verde Nuclear Generating Station Units 1 and 2 lease agreements limit the Company's ability, without consent of the owner participants in the lease transactions: (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. The Credit Facility imposes similar restrictions regardless of credit ratings. Financing Activities The Company currently has no maturities of long-term financings during the period of 2001 through 2004, not considering the impact of the acquisition of the Western Resources' electric utility operations. However, during this period, the Company could enter into long-term financings for the purpose of strengthening its balance sheet, funding growth and reducing its cost of 43 capital. The Company continues to evaluate its investment and debt retirement options to optimize its financing strategy and earnings potential. No additional first mortgage bonds may be issued under the Company's mortgage. The amount of SUNs that may be issued is not limited by the SUNs indenture. However, debt to capital requirements in certain of the Company's financial instruments would ultimately restrict the Company's ability to issue SUNs. Proposed Holding Company Plan Previously, the Company provided details of its proposed holding company plan as contemplated in response to the implementation dates established under the Restructuring Act before it was amended in March of 2001 (see "Restructuring of the Electric Utility Industry" above). As a result of the amendments to the Restructuring Act delaying customer choice and corporate restructuring for five years, the Company has modified its previously reported holding company plan. Currently, the Company plans to implement a holding company structure as permitted under the amended Restructuring Act, without corporate separation of the regulated and deregulated activities. This structure provides for a holding company whose current holdings will be the Company, Avistar and other inactive unregulated subsidiaries. This is expected to be effected through a share exchange between current company shareholders and the proposed holding company, PNM Resources, which is currently a wholly-owned subsidiary of the Company. Avistar and the other inactive unregulated subsidiaries are expected to become wholly-owned subsidiaries of the holding company. There are no current plans to provide the proposed holding company with significant debt financing. The Company is unable to predict the form its further restructuring will take under the delayed implementation of customer choice. The PRC issued an order approving formation of a holding company on June 28, 2001. The order limits the proposed utility subsidiary's ability to pay dividends to the parent holding company to annual current earnings determined on a rolling four quarter average and imposes certain regulatory requirements on the construction of merchant generation plants. The Company believes that certain conditions imposed by the PRC order are unnecessarily burdensome and could have a negative impact on the Company's ability to execute its growth strategy. On July 27, 2001, the Company asked the PRC to reconsider certain conditions imposed by the order. The PRC has until August 16 to respond to the Company's request for rehearing. If the PRC does not act by then, the request is automatically denied. The Company is unable to predict the outcome of this proceeding. If the result of the request for rehearing is unfavorable, the Company will consider filing an appeal to the New Mexico Supreme Court. Stock Repurchase On August 8, 2000, the Company's Board of Directors approved a plan to repurchase up to $35 million of the Company's common stock through the end of the first quarter of 2001. From August 8, 2000 through December 31, 2000 Company repurchased an additional 417,900 shares of its outstanding common stock at a cost of $9.0 million. The Company made no repurchases of its stock during the six months ended June 30, 2001. The Company has no current authorization from its Board of Directors to acquire stock. Dividends The Company's board of directors reviews the Company's dividend policy on a continuing basis. The declaration of common dividends is dependent upon a number of factors including the extent to which cash flows will support 44 dividends, the availability of retained earnings, the financial circumstances and performance of the Company, the PRC's decisions on the Company's various regulatory cases currently pending, the effect of deregulating generation markets and market economic conditions generally. In addition, the ability to recover stranded costs in deregulation (as amended), conditions imposed on holding company formation, future growth plans and the related capital requirements and standard business considerations may also affect the Company's ability to pay dividends. Capital Structure The Company's capitalization percentage, including current maturities of long-term debt, at June 30, 2001 and December 31, 2000 is shown below: June 30, December 31, 2001 2000 --------- ---------- Common Equity....................... 50.7% 48.6% Preferred Stock..................... 0.7 0.7 Long-term Debt...................... 48.6 50.7 --------- ---------- Total Capitalization*............ 100.0% 100.0% ========= ========== * Total capitalization does not include as debt the present value of the Company's lease obligations for PVNGS Units 1 and 2 and EIP, which was $165 million as of June 30, 2001 and $166 million as of December 31, 2000. OTHER ISSUES FACING THE COMPANY RECOVERY OF CERTAIN COSTS UNDER THE RESTRUCTURING ACT Stranded Costs The Restructuring Act, as amended, recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers ("stranded costs"). Stranded costs represent all costs associated with generation-related assets, currently in rates, in excess of the expected competitive market price over the life of those assets and include plant decommissioning costs, regulatory assets, and lease and lease-related costs. Utilities will be allowed to recover no less than 50% of stranded costs through a non-bypassable charge on all customer bills for five years after implementation of customer choice. The PRC could authorize a utility to recover up to 100% of its stranded costs if the PRC finds that recovery of more than 50%: (i) is in the public interest; (ii) is necessary to maintain the financial integrity of the public utility; (iii) is necessary to continue adequate and reliable service; and (iv) will not cause an increase in rates to residential or small business customers during the transition period. The Restructuring Act, as amended, also allows for the recovery of nuclear decommissioning costs by means of a separate wires charge over the life of the underlying generation assets (see "NRC Prefunding" below). The calculation of stranded costs is subject to a number of highly sensitive assumptions, including the date of open access, appropriate discount rates and projected market prices, among others. The Restructuring Act, as amended, requires the Company to file a transition plan which includes provisions for the recovery of stranded costs and other expenses associated with 45 the transition to a competitive market no later than January 1, 2005. The Company is unable to predict the amount of stranded costs that it may file to recover at that time. The Company's previous proposal to recover its stranded costs under the original customer choice implementation dates would not accurately represent the Company's expected stranded costs under the amended implementation dates of the Restructuring Act. Approximately $151 million of costs associated with the power supply and energy services businesses under the Restructuring Act were established as regulatory assets. Because of the Company's belief that recovery is probable, these regulatory assets continue to be classified as regulatory assets, although the Company has discontinued Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) and adopted Statement of Financial Accounting Standards No. 101, "Regulated Enterprises--Accounting for the Discontinuance of Application of FASB Statement 71." The amendments to the Restructuring Act will allow the Company to pursue the collection of $100 million of coal mine decommissioning costs. The Company intends to seek such recovery in its next rate case filing and believes that such costs are fully recoverable. The Company believes that any remaining stranded cost assets will be fully recovered in current or future rates, including non-bypassable wires charge. The Company believes that the Restructuring Act, as amended, if properly applied provides an opportunity for recovery of a reasonable amount of stranded costs should such costs exist at the point of separation. If regulatory orders do not provide for a reasonable recovery, the Company is prepared to vigorously pursue judicial remedies. The PRC will make a determination and quantification of stranded cost recovery prior to implementation of restructuring. The determination may have an impact on the recoverability of the related assets and may have a material effect on the future financial results and position of the Company. Transition Cost Recovery In addition, the Restructuring Act, as amended, authorizes utilities to recover in full any prudent and reasonable costs incurred in implementing full open access ("transition costs"). These transition costs are currently scheduled to be recovered through 2012 by means of a separate wires charge. The PRC may extend this date by up to one year. The Company is unable to predict the amount of transition costs it may incur. To date, the Company has capitalized $22.4 million of expenditures that meet the Restructuring Act's definition of transition-related costs. Transition costs for which the Company will seek recovery include professional fees, financing costs, consents relating to the transfer of assets, management information system changes including billing system changes and public and customer education and communications. Recoverable transition costs are currently being capitalized and will be amortized over the recovery period to match related revenues. The Company intends to vigorously pursue remedies available to it should the PRC disallow recovery of reasonable transition costs. Costs not recoverable will be expensed when incurred unless these costs are otherwise permitted to be capitalized under current and future accounting rules. If the amount of non-recoverable transition costs is material, the resulting charge to earnings may have a material effect on the future financial results and position of the Company. 46 NRC Prefunding Pursuant to NRC rules on financial assurance requirements for the decommissioning of nuclear power plants, the Company has a program for funding its share of decommissioning costs for PVNGS through a sinking fund mechanism (see "PVNGS Decommissioning Funding"). The NRC rules on financial assurance became effective on November 23, 1998. The amended rules provide that a licensee may use an external sinking fund as the exclusive financial assurance mechanism if the licensee recovers estimated decommissioning costs through cost of service rates or a "non-bypassable charge". Other mechanisms are prescribed, such as prepayment, surety methods, insurance and other guarantees, to the extent that the requirements for exclusive reliance on the fund mechanism are not met. The Restructuring Act, as amended, allows for the recoverability of 50% up to 100% of stranded costs including nuclear decommissioning costs (see "Stranded Costs"). The Restructuring Act, as amended, specifically identifies nuclear decommissioning costs as eligible for separate recovery over a longer period of time than other stranded costs if the PRC determines a separate recovery mechanism to be in the public interest. In addition, the Restructuring Act, as amended, states that it does not require the PRC to issue any order which would result in loss of eligibility to exclusively use external sinking fund methods for decommissioning obligations pursuant to Federal regulations. When final determination of stranded cost recovery is made and if the Company is unable to meet the requirements of the NRC rules permitting the use of an external sinking fund because it is unable to recover all of its estimated decommissioning costs through a non-bypassable charge, the Company may have to pre-fund or find a similarly capital intensive means to meet the NRC rules. There can be no assurance that such an event will not negatively affect the funding of the Company's growth plans. PROPOSED ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS On November 9, 2000, the Company and Western Resources announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. Due to recent actions by the KCC, the transaction cannot be accomplished under the terms of the present acquisition agreement if the orders remain in effect (see below). Present Acquisition Agreement Under the present agreement and plan of restructuring and merger, the Company and Western Resources, whose utility operations consist of its Kansas Power and Light ("KPL") division and Kansas Gas and Electric ("KGE") subsidiary, will both become subsidiaries of a new holding company to be named at a future date. Prior to and as a condition to, the consummation of this combination, Western Resources will reorganize all of its non KPL and KGE assets, including its 85% stake in Protection One and its 45% investment in ONEOK, into Westar Industries which will be spun off to Western Resources' shareholders prior to the acquisition of Western's electric utility assets by the Company. 47 Under the present agreement, the new holding company will issue 55 million of its shares, subject to adjustment, to Western Resources' shareholders and Westar Industries and 39 million shares to the Company's shareholders. Before any adjustments, the new company will have approximately 94 million shares outstanding, of which approximately 41% will be owned by former Company shareholders and 59% will be owned by former Western Resources shareholders and Westar Industries. In the present transaction, each Company share will be exchanged on a one-for-one basis for shares in the new holding company. The portion of each Western Resources share not converted into Westar stock in connection with the spin-off will be exchanged for a fraction of a share of the new holding company in accordance with an exchange ratio to be finalized at closing, depending on the impact of certain adjustments to the transaction consideration. Under the present agreement, Western Resources and Westar Industries have been given an incentive to reduce Western Resources net debt balance prior to the consummation of the transaction. The present agreement contains a mechanism to adjust the transaction consideration based on certain activities not affecting the utility operations, which increase the equity of the utility. In addition, Westar Industries has the option of making equity infusions into Western Resources that will be used to reduce the utility's net debt balance prior to closing. Up to $407 million of such equity infusions may be used to purchase additional new holding company common and convertible preferred stock. The effect of such activities would be to increase the number of new holding company shares to be issued to all Western Resources shareholders (including Westar Industries) in the present transaction. In February 2001, Westar purchased 14.4 million Western Resources common shares at $24.358 per share (based on a 20 day look-back price at February 28, 2001) at an aggregate price of $350 million. As a result of this equity contribution, under the present agreement, the acquisition consideration may be adjusted to include an additional 4.3 million shares of the new holding company depending on the impact of future transactions between Western Resources and Westar. Under the present agreement, the transaction will be accounted for as a reverse acquisition by the Company as the former Western Resources shareholders will receive the majority of the voting interests in the new holding company. For accounting purposes, Western Resources will be treated as the acquiring entity. Accordingly, all of the assets and liabilities of the Company will be recorded at fair value in the business combination as required by the purchase method of accounting. In addition, the operations of the Company will be reflected in the operations of the combined company only from the date of acquisition. Based on the volume weighted average closing price of the Company's common stock over the two days prior and two days subsequent to the announcement of the transaction of $24.149 per share, the indicated equity consideration of the present transaction is approximately $945 million, excluding the potential issuance of additional shares discussed above. There is approximately $2.9 billion of existing Western Resources debt giving the transaction an aggregate enterprise value of approximately $3.8 billion. There are plans for the new holding company to reduce and refinance a portion of the Western Resources' debt, assumed in the present transaction. At closing, Jeffrey E. Sterba, present chairman, president and chief executive officer of the Company, will become chairman, president and chief executive officer of the new holding company, and David C. Wittig, present chairman, president and chief executive officer of Western Resources, will become chairman, president and chief executive officer of Westar Industries. The Board of Directors of the new company will consist of six current Company board 48 members and three additional directors, two of whom will be selected by the Company from a pool of candidates nominated by Western Resources, and one of whom will be nominated by Westar Industries. The new holding company will be headquartered in New Mexico. Headquarters for the Kansas utilities will remain in Kansas. Under the present agreement, the Company expects that the shareholders of the new holding company will receive the Company's dividend. The Company's current annual dividend is $0.80 per share. There can be no assurance however that any funds, property or shares will be legally available to pay dividends at any given time or if available, the new holding company's Board of Directors will declare a dividend. Under the present agreement, the successful split-off of Westar Industries from Western Resources is required prior to the consummation of the transaction. The transaction is also conditioned upon, among other things, approvals from both companies' shareholders and customary regulatory approvals from the KCC, the PRC, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Federal Communications Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In addition, an adverse regulatory outcome related to other actions involving rate making or approval of regulatory plans, may affect the consummation of the transaction. The new holding company is expected to register as a holding company with the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. Recent Actions by the KCC On May 8, 2001, the KCC commenced an investigation of the proposed split-off of Westar Industries from Western Resources and whether the transaction will adversely affect the ability of Western Resources' electric utility operations to provide efficient and sufficient electric utility service at just and reasonable rates to its customers in the state of Kansas. The successful split-off of Westar is a condition of the proposed acquisition of Western Resources' electric utility assets. On July 20, 2001, the KCC issed an order prohibiting Western from proceeding with the split-off of Westar Industries. The KCC ruled that the split-off, as presently designed, is inconsistent with the public interest. The KCC also ruled that the adverse impacts of the split-off on ratepayers could not be cured by a merger and directed Western to file a financial plan within 90 days to restore Western's financial ratings to the investment grade level of similarly situated electric public utilities. Western has filed for reconsideration of the order. On July 25, 2001, the KCC issued an order reducing the rates of Western's electric utilities by the net amount of $22.7 million annually. Western had sought a combined increase of approximately $151 million annually. Other recommendations in the case would have reduced rates by up to $92 million annually. Western has filed for reconsideration of the order. 49 On July 30, 2001, the Company and Western issued a joint release stating that the transaction as presently designed would be difficult to accomplish if the KCC orders remain in effect. The release announced that the Company and Western would begin discussions on how to modify the transaction to address KCC concerns. On August 13, 2001, the Company announced that Western had decided to discontinue the talks about modifying the transaction and desired to attempt to obtain regulatory approval of the transaction as currently structured. The Company announced that it continues to believe that the transaction cannot be accomplished on its present terms due to the KCC orders. In addition the Company announced that it believes that the rate case order will result in a material adverse effect on the financial condition of the combined companies and that there will be a failure of key conditions to consummation of the transaction if the KCC orders remain in effect. Western has advised the Company that it does not believe that the rate case order results in a material adverse effect. WESTERN UNITED STATES WHOLESALE POWER MARKET A significant portion of the Company's earnings in 2001 was derived from the Company's wholesale power trading operations which benefited from the strong demand and high wholesale prices in the Western United States. These market conditions were primarily driven by the electric power supply shortages in the Western United States. As a result of the supply imbalance, the wholesale power market in the Western United States has become extremely volatile and, while providing many marketing opportunities, continues to present significant risk to companies selling power into this marketplace. The power market in the Western United States has been the subject of widespread national attention and relevant legal and regulatory developments continue to occur at a rapid pace. At the heart of the situation were flaws in the California deregulation legislation and a significant imbalance between electric supply and demand. These circumstances have been aggravated by other factors such as increases in gas supply costs, weather conditions and transmission constraints. Congress and the California legislature are considering various legislation that would provide long or short-term relief, including potentially price caps on the wholesale price of electricity that could be charged, relaxation of certain environmental standards, and windfall profit taxes on sellers into the California wholesale market. The FERC and the California Public Utilities Commission ("CPUC") have also entered a series of orders addressing, respectively, the wholesale pricing of electricity into the California market and the retail pricing of electricity to California consumers. These initiatives, individually or collectively, have recently put significant downward pressure on wholesale prices. The Company cannot predict the ultimate outcome of these governmental initiatives and their long-term effect on the Western United States power market or on the Company's ability to market into the California market. During 2001, regional wholesale electricity prices reached over $1,000 per MWh mainly due to the electric power shortages in the West although current price levels are much depressed from this level. Two of California's major utilities, SCE and PG&E, have been unable to fully recover their wholesale power costs from their ratepayers. As a result, both utilities experienced severe liquidity constraints that caused PG&E to seek bankruptcy protection while SCE has been forced to consider bankruptcy. 50 In response to the turmoil in the California energy market, the FERC initially imposed a "soft" price cap of $150 per MWh for sales to the California Power Exchange ("Cal PX") and the California Independent System Operator ("Cal ISO") that required any wholesale sales of electricity into the these markets be capped at $150 MWh unless the seller could demonstrate that its costs exceed the cap. This price cap was effectively modified by FERC orders issued in March and April 2001 that directed certain power suppliers to provide refunds in excess of $100 million for overcharges calculated on the basis of a formula that sanctioned wholesale prices considerably in excess of the $150/MWh level. On April 26, 2001, the FERC adopted an order establishing prospective mitigation and a monitoring plan for the California wholesale markets and which established a further investigation of public utility rates in wholesale Western energy markets. The plan reflected in the April 26 order replaced the $150/MWh soft cap previously established and would apply during periods of system emergency. Thereafter, on June 19, 2001, the FERC issued still another order that changed the previous orders and expanded the price mitigation approach of the April 26 order to all of the western region. As a result of the price mitigation plan and other factors, such as moderate weather in California and lower gas prices, wholesale electric prices declined significantly at the end of the second quarter and remained low subsequent to the end of the second quarter. The Company is unable to predict the impact the price mitigation plan will ultimately have on the wholesale market, but expects that if wholesale electric prices remain at current levels, future operating revenues from Generation and Trading will be significantly lower than in the first half of 2001. The June 19 order also directed a FERC administrative law judge to convene a settlement conference to address potential refunds owed by sellers into the California market. The settlement conference, in which the Company participated, was ultimately unsuccessful, but the administrative law judge called in his recommendation to the FERC for an evidentiary hearing to resolve the dispute, suggesting that refunds were due; however, the estimated refunds were significantly lower than demanded by California, and in most instances, were offset by the amounts due suppliers from the Cal PX and Cal ISO. California had demanded refunds of approximately $9 billion from power suppliers. On July 25, 2001, acting on the recommendation of the administrative law judge, the FERC ordered an expedited fact-finding hearing to evaluate refunds for spot market transactions in California. The FERC also ordered a preliminary hearing to determine whether refunds are also due in the Pacific Northwest. The Company is unable to predict the ultimate outcome of these FERC proceedings, or whether the Company will be directed to make any refunds as the result of a resulting FERC order. In 2001, approximately $2 million in wholesale power sales by the Company were made directly to the Cal PX, which was the main market for the purchase and sale of electricity in the state in the beginning of 2001 or the Cal ISO which manages the state's electricity transmission network. In January and February 2001, SCE and PG&E, major purchasers of power from the California PX and ISO, defaulted on payments due the Cal PX for power purchased from the PX in 2000. These defaults caused the Cal PX to seek bankruptcy protection. The Company has filed its proof of claims in the bankruptcy proceeding. Total amounts due from the Cal PX or Cal ISO for power sold to them total approximately $7 million. The Company has provided allowances for the total amount due from the Cal PX and Cal ISO. Prior to its bankruptcy filing, the Cal PX undertook to charge back these defaults of SCE and PG&E to other market participants, in proportion to their participation in the markets. The Company was invoiced for $2.3 million as its proportionate share under the Cal PX tariff. The Company, as well as a number of power marketers and generators, filed complaints with the FERC to halt 51 the Cal PX's attempt to collect these payments under the charge-back mechanism, claiming the mechanism was not intended for these purposes, and even if it was so intended, such an application was unreasonable and destabilizing to the California power market. The FERC has issued a ruling on these complaints eliminating the "charge-back" mechanism. With the demise of the Cal PX in February 2001, the California Department of Water Resources ("Cal DWR") commenced a program of purchasing electric power needed to supply California utility customers serviced by PG&E and SCE as these utilities lacked the liquidity to purchase supplies. The purchases are currently financed by legislative appropriation, but this funding is expected to be replaced with the issuance of revenue bonds by the state under recent legislation signed by the California governor. These bonds are expected to be repaid by the utility ratepayers. In the first quarter of 2001, the Company began to sell power to the Cal DWR. The Company regularly monitors its credit risk with regard to its Cal DWR sales and believes its exposure is prudent. In addition to sales directly to California, the Company sells power to customers in other jurisdictions who sell to California and whose ability to pay the Company may be dependent on payment from California. The Company is unable to determine whether its non-California power sales ultimately are resold in the California market. The Company's credit risk is monitored by its Risk Management Committee, which is comprised of senior finance and operations managers. The Company seeks to minimize its exposure through established credit limits, a diversified customer base and the structuring of transactions to take advantage of off-setting positions with its customers. To the extent these customers who sell power into California are dependent on payment from California to make their payments to the Company, the Company may be exposed to credit risk which did not exist prior to the California situation. In 2001, in response to the increased credit risk and market price volatility described above, the Company provided an additional allowance against revenue of $6.7 million for anticipated losses to reflect management's estimate of the increased risk in the wholesale power market and its impact on 2001 revenues. This determination was based on a methodology that considers the credit ratings of its customers and the price volatility in the marketplace, among other things. Based on information available at June 30, 2001, the Company believes the total allowance for anticipated losses, currently established at $15.2 million, is adequate for management's estimate of potential uncollectible accounts. The Company will continue to monitor the wholesale power marketplace and adjust its estimates accordingly. The CPUC has commenced an investigation into the functioning of the California wholesale power market and its associated impact on retail rates. The Company, along with other power suppliers in California, has been served with a subpoena in connection with this investigation and has responded to the subpoena. The Company has been advised that the California Attorney General is conducting an investigation into possibly unlawful, unfair or anti-competitive behavior affecting electricity rates in California, and that Company documents will be subpoenaed in the future in connection with this investigation. Other related investigations have been commenced by other federal and state governmental bodies. In addition, there are several class action lawsuits that have been filed in California against generators and wholesale sellers of energy into the California market. These actions allege, in essence, that the defendants engaged in unlawful and unfair business practices to manipulate the wholesale energy market, fix prices and restrain supply, and thereby drive up prices. The Company is not a named defendant in any of these actions. 52 The Company does not believe that these matters will have a material adverse effect on its results of operations or financial position. As noted above, SCE has publicly stated that it may be forced to declare bankruptcy. SCE is a 15.8% participant in PVNGS and a 48.0% participant in Four Corners. Pursuant to an agreement among the participants in PVNGS and an agreement among the participants in Four Corners Units 4 and 5, each participant is required to fund its proportionate share of operation and maintenance, capital, and fuel costs of PVNGS and Four Corners Units 4 and 5. The Company estimates SCE's total monthly share of these costs to be approximately $7.1 million for PVNGS and $8.0 million for Four Corners. The agreements provide that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant for a period of six months. During this time the defaulting participant is entitled to its share of the power generated by the respective station. After this grace period, the defaulting participant must make its payments in arrears before it is entitled to its continuing share of power. SCE has not defaulted on its payment obligations with respect to PVNGS and Four Corners. The Company is unable to predict whether the California situation will cause SCE to default on its payment obligations. Implementation of New Customer Billing System On November 30, 1998, the Company implemented a new customer billing system. Due to a significant number of problems associated with the implementation of the new billing system, the Company was unable to generate appropriate bills for all its customers through the first quarter of 1999 and was unable to analyze delinquent accounts until November 1999. As a result of the delay of normal collection activities, the Company incurred a significant increase in delinquent accounts, many of which occurred with customers that no longer have active accounts with the Company. As a result, the Company significantly increased its estimated bad debt costs throughout 1999 and 2000. The Company continued its analysis and collection efforts of its delinquent accounts resulting from the problems associated with the implementation of the new customer billing system throughout 2000 and identified additional bad debt exposure. By the end of 2000, the Company completed its analysis of its delinquent accounts and resumed its normal collection procedures. In addition, due to the significantly higher natural gas prices experienced in November and December 2000, the Company increased its bad debt expense by approximately $1 million for the six months ended June 30, 2001 and $2 million for the year ended December 31, 2000 in anticipation of higher than normal delinquency rates. The Company expects this trend to continue as long as natural gas prices remain higher than historical levels. Based upon information available at June 30, 2001, the Company believes the allowance for doubtful accounts of $8.6 million is adequate for management's estimate of potential uncollectible accounts. 53 The following is a summary of the allowance for doubtful accounts during the six months ended June 30, 2001 and the year ended December 31, 2000:
June 30, December 31, 2001 2000 -------------- ------------- Allowance for doubtful accounts, beginning of year.................................................. $ 8,963 $12,504 Bad debt expense........................................... 2,131 9,980 Less: Write off (adjustments) of uncollectible accounts... 2,514 13,521 ------------ ------------- Allowance for doubtful accounts, end of year .............. $ 8,580 $ 8,963 ============ =============
Effects of Certain Events on Future Revenues The Company's 100 MW power sale contract with San Diego Gas and Electric Company ("SDG&E") expired on April 30, 2001 following FERC's acceptance for filing of a cancellation notice filed by the Company. The Company expects to replace these revenues, based on current market conditions. In addition, previously reported litigation between the Company and SDG&E regarding prior years' contract pricing has been resolved in the Company's favor. On October 1, 1999, Western Area Power Administration ("WAPA") filed a petition at the FERC requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA under the Company's Open Access Transmission Tariff on behalf of the United States Department of Energy ("DOE") as contracting agent for Kirtland Air Force Base ("KAFB"). On April 13, 2001, the FERC entered an order favorable to the Company, denying the WAPA transmission application. WAPA requested rehearing of FERC's April 13, 2001 order. In a proposed order issued on June 13, 2001, FERC granted WAPA's request for rehearing and ordered the Company to provide transmission service. If the parties do not agree upon the terms for that service, including compensation, FERC will establish those terms after a negotiation and briefing process. The June 13 order is a "proposed" order, and is not subject to requests for rehearing or judicial review. An order establishing terms and conditions (including compensation for transmission service) would be a "final" order that would be subject to requests for rehearing and to judicial review. The effect of the FERC's order to provide transmission service, instead of the current retail sale that the Company makes to DOE on behalf of KAFB, depends upon the final terms of any FERC order as well as the Company's ability to sell the power to a different customer and the price that the Company would obtain if it makes such a sale. The Company is evaluating its legal options in relation to the "proposed" order or any resulting "final" order. In a related PRC proceeding, the parties are pursuing informal settlement discussions and awaiting a PRC order on the scope of the case (See Item 3. - "Legal Proceedings - Other Proceedings - KAFB Contract"). COAL FUEL SUPPLY In 1996, the Company was notified by SJCC that the Navajo Nation proposed to select certain properties within the San Juan and La Plata Mines (the "mining properties") pursuant to the Navajo-Hopi Land Settlement Act of 1974 (the "Act"). The mining properties are operated by SJCC under leases from the BLM and comprise a portion of the fuel supply for the SJGS. An administrative appeal by SJCC is pending. In the appeal, SJCC argued that 54 transfer of the mining properties to the Navajo Nation may subject the mining operations to taxation and additional regulation by the Navajo Nation, both of which could increase the price of coal that might potentially be passed on to the SJGS through the existing coal sales agreement. The Company is monitoring the appeal and other developments on this issue and will continue to assess potential impacts to the SJGS and the Company's operations. The Company is unable to predict the ultimate outcome of this matter. FUEL, WATER AND GAS NECESSARY FOR GENERATION OF ELECTRICITY The Company's generation mix for 2001 was 68.25% coal, 28.40% nuclear and 3.35% gas and oil. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits and the generally abundant supply of nuclear fuel, the Company believes that adequate sources of fuel are available for its generating stations. Water for Four Corners and SJGS is obtained from the San Juan River. BHP holds rights to San Juan River water and has committed a portion of those rights to Four Corners through the life of the project. The Company and Tucson have a contract with the USBR for consumption of 16,200 acre feet of water per year for the SJGS. The contract expires in 2005. In addition, the Company was granted the authority to consume 8,000 acre feet of water per year under a state permit that is held by BHP. The Company is of the opinion that sufficient water is under contract for the SJGS through 2005. The Company has signed a contract with the Jicarilla Apache Tribe for a twenty-two year term, beginning in 2006, for replacement of the current USBR contract for 16,200 acre feet of water. The contract must still be approved by the USBR and is also subject to environmental approvals. The Company is actively involved in the San Juan River Recovery Implementation Program to mitigate any concerns with the taking of the negotiated water supply from a river that contains endangered species and critical habitat. The Company believes that it will continue to have adequate sources of water available for its generating stations. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. These contracts are generally sufficient to meet the Company's peak-day demand. The Company serves certain cities which depend on EPNG or Transwestern Pipeline Company for transportation of gas supplies. Because these cities are not directly connected to the Company's transmission facilities, gas transported by these companies is the sole supply source for those cities. The Company believes that adequate sources of gas are available for its distribution systems. NEW SOURCE REVIEW RULES The United States Environmental Protection Agency ("EPA") has proposed changes to its New Source Review ("NSR") rules that could result in many actions at power plants that have previously been considered routine repair and maintenance activities (and hence not subject to the application of NSR requirements) as now being subject to NSR. In November 1999, the Department of Justice at the request of the EPA filed complaints against seven companies alleging the companies over the past 25 years had made modifications to their plants in violation of the NSR requirements, and in some cases the New Source Performance Standards ("NSPS") regulations. Whether or not the EPA will prevail is unclear at this time. The EPA has reached a settlement with one of the 55 companies sued by the Justice Department. Discovery continues in the pending litigation. No complaint has been filed against the Company, and the Company believes that all of the routine maintenance, repair, and replacement work undertaken at its power plants was and continues to be in accordance with the requirements of NSR and NSPS. However, by letter dated October 23, 2000, the New Mexico Environment Department ("NMED") made an information request of the Company, advising the Company that the NMED was in the process of assisting the EPA in the EPA's nationwide effort "of verifying that changes made at the country's utilities have not inadvertently triggered a modification under the Clean Air Act's Prevention of Significant Determination ("PSD") policies." The Company has responded to the NMED information request. The nature and cost of the impacts of EPA's changed interpretation of the application of the NSR and NSPS, together with proposed changes to these regulations, may be significant to the power production industry. However, the Company cannot quantify these impacts with regard to its power plants. It is also unknown what changes in EPA policy, if any, may occur in the NSR area as a result of the change in administration in Washington. The National Energy Policy released May 2001 by the National Energy Policy Development Group, called for a review of the pending NSR enforcement actions and that review is currently being undertaken by the EPA and the United States Attorney General. If the EPA should prevail with its current interpretation of the NSR and NSPS rules, the Company may be required to make significant capital expenditures which could have a material adverse effect on the Company's financial position and results of operations. COMPLIANCE WITH ENVIRONMENTAL LAWS AND REGULATIONS The normal course of operations of the Company necessarily involves activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Sources of potential environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes. The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, the Company records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts). The Company's recorded estimated minimum liability to remediate its identified sites is $[6.8] million. The ultimate cost to clean up the Company's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur. The Company 56 believes that, due to these uncertainties, it is remotely possible that cleanup costs could exceed its recorded liability by up to $[11.6] million. The upper limit of this range of costs was estimated using assumptions least favorable to the Company. In 2001, the Company anticipates spending $1.4 million for remediation and $0.7 million for control and prevention. The majority of the June 30, 2001 environmental liability is expected to be paid over the next five years, funded by cash generated from operations. Future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company. NATURAL GAS EXPLOSION On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. The cause of the leak is unknown and the Company is conducting an investigation into the explosion. One lawsuit against the Company for personal injuries by a person working in the building at the time of the explosion has been filed and served on the Company. Several claims for property and business interruption damages have been resolved by the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur. There can be no assurance that the outcome of this matter will not have a material impact on the results of operations and financial position of the Company. NAVAJO NATION TAX ISSUES APS, the operating agent for Four Corners, has informed the Company that in March 1999, APS initiated discussions with the Navajo Nation regarding various tax issues in conjunction with the expiration of a tax waiver, in July 2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to the possessory interest tax and the business activity tax associated with the Four Corners operations on the reservation. The Company believes that the resolution of these tax issues will require an extended process and could potentially affect the cost of conducting business activities on the reservation. The Company is unable to predict the ultimate outcome of discussions with the Navajo Nation regarding these tax issues. LANDOWNER ENVIRONMENTAL CLAIMS Certain landowners owning property in the vicinity of the San Juan Generating Station have given notice to the Company of their intent to file suit against the Company and the other owners of the generating station. The asserted bases for the threatened litigation encompass a broad spectrum of allegations, including improper discharge of wastes and failure to remediate such discharges, poisoning of drinking waters, wrongful death and injury to persons, harm to landowner property, negligence, unnatural climate change, destruction of documents, racial discrimination, hostile work environment for employees at the plant and wrongful discharge of certain employees. The Company is in the process of reviewing these allegations and to date no suit has been filed. The Company has been informed that similar allegations have been made by the same landowners against Arizona Public Service Company, as operator of the Four Corners Power Plant, of which the Company is a co-owner. 57 NEW AND PROPOSED ACCOUNTING STANDARDS Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"): The Company implemented SFAS 133, as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133, as amended, also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. Because the Company's derivative instruments as defined by SFAS 133, as amended, are currently marked-to-market or are classified as cash flow hedges, the adoption of SFAS 133, as amended, did not have an impact on the net earnings of the Company. However, the adoption of SFAS 133, as amended, did increase comprehensive income by $6.1 million, net of taxes for the recording of the Company's cash flow hedges. The physical contracts will subsequently be recognized as a component of the cost of purchased power when the actual physical delivery occurs. At January 1, 2001, the derivative instruments designated as cash flow hedges had a gross asset position of $9.9 million on the hedged transactions. See Note 4 for financial instruments currently marked-to-market. It is a common practice within the electric utility industry to net offsetting purchase and sales contracts between two or more counterparties to facilitate transmission. This is commonly referred to as a "book-out." Whether a book-out occurs is dependant on a number of factors, including agreement by all parties in the chain of the transaction, efficiency of the transaction flow, congestion on the electrical transmission system, and system reliability issues. Book-outs do not occur until a short time before the electricity is due to be physically delivered, no matter when the original contracts in the chain were entered into, and have no legal standing should one of the parties in the chain default. The Derivatives Implementation Group ("DIG") of the FASB has reached a conclusion that all contracts for the sale or purchase of electricity that are subject to being booked out, whether that is the intent of the counterparties or not, may qualify for the normal sale or normal purchase exception if certain criteria are met. If the Company's contracts do not meet these criteria, it may be required to mark-to-market its transactions that it has classified as normal purchases and normal sales. The effective date for compliance with this implementation guide is June 30, 2001. The Company is currently in the process of determining the impact of this conclusion. Decommissioning: The Staff of the Securities and Exchange Commission ("SEC") has questioned certain of the current accounting practices of the electric industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of 58 electric utilities. In February 2000, the Financial Accounting Standards Board ("FASB") issued an exposure draft regarding Accounting for Obligations Associated with the Retirement of Long-Lived Assets ("Exposure Draft"). The Exposure Draft requires the recognition of a liability for an asset retirement obligation at fair value. In addition, present value techniques used to calculate the liability must use a credit adjusted risk-free rate. Subsequent remeasures of the liability would be recognized using an allocation approach. The Company has not yet determined the impact of the Exposure Draft. DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS Statements made in this filing that relate to future events are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of the Company are based upon current expectations and are subject to risk and uncertainties, as are the forward-looking statements with respect to the benefits of the Company's proposed acquisition of Western Resources and the businesses of the Company and Western Resources. The Company assumes no obligation to update this information. Because actual results may differ materially from expectations, the Company cautions readers not to place undue reliance on these statements. A number of factors, including weather, fuel costs, changes in supply and demand in the market for electric power, the performance of generating units and transmission system, and state and federal regulatory and legislative decisions and actions, including rulings issued by the New Mexico Public Regulation Commission pursuant to the Electric Utility Industry Restructuring Act of 1999, as amended, and in other cases now pending or which may be brought before the PRC and any action by the New Mexico Legislature to further amend or repeal that Act, or other actions relating to restructuring or stranded cost recovery, or federal or state regulatory, legislative or legal action connected with the California wholesale power market, could cause the Company's results or outcomes to differ materially from those indicated by such forward-looking statements in this filing. In addition, factors that could cause actual results or outcomes related to the proposed acquisition of Western Resources to differ materially from those indicated by such forward looking statements include, risks and uncertainties relating to: the possibility that shareholders of the Company or Western Resources will not approve the transaction, the risks that the businesses will not be integrated successfully, the risk that the benefits of the transaction may not be fully realized or may take longer to realize than expected, disruption from the transaction making it more difficult to maintain relationships with clients, employees, suppliers or other third parties, conditions in the financial markets relevant to the proposed transaction, the receipt of regulatory and other approvals of the transaction, that future circumstances could cause business decisions or accounting treatment to be decided differently than now intended, changes in laws or regulations, changing governmental policies and regulatory actions with respect to allowed revenue requirements, rates of return on equity and equity ratio limits, industry and rate structure, stranded cost recovery, operation of nuclear power facilities, acquisition, disposal, depreciation and amortization of assets and facilities, operation and construction of plant facilities, recovery of fuel and purchased power costs, decommissioning costs, present or prospective wholesale and retail 59 competition (including retail wheeling and transmission costs), political and economic risks, changes in and compliance with environmental and safety laws and policies, weather conditions (including natural disasters such as tornadoes), population growth rates and demographic patterns, competition for retail and wholesale customers, availability, pricing and transportation of fuel and other energy commodities, market demand for energy from plants or facilities, changes in tax rates or policies or in rates of inflation or in accounting standards, unanticipated delays or changes in costs for capital projects, unanticipated changes in operating expenses and capital expenditures, capital market conditions, competition for new energy development opportunities and legal and administrative proceedings (whether civil, such as environmental, or criminal) and settlements, and the impact of Protection One's financial condition on Western Resources' consolidated results. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices and also adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. Information about market risk is set forth in Note 4 to the Notes to the Consolidated Financial Statements and incorporated by reference. The following additional information is provided. The Company uses value at risk ("VAR") to quantify the potential exposure to market movement on its open contracts and excess generating assets. The VAR is calculated utilizing the variance/co-variance methodology over a three day period within a 99% confidence level. The Company's VAR as of June 30, 2001 from its electric trading contracts was $37.5 million. The Company's wholesale power marketing operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases. The Company's VAR calculation considers this exposure. The Company's VAR is regularly monitored by the Company's Risk Management Committee which is comprised of senior finance and operations managers. The Risk Management Committee has put in place procedures to ensure that increases in VAR are reviewed and, if deemed necessary, acted upon to reduce exposures. In addition, the Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to access and monitor the financial conditions of counterparties. Credit exposure is also regularly monitored by the Company's Risk Management committee. The VAR represents an estimate of the potential gains or losses that could be recognized on the Company's wholesale power marketing portfolio given current volatility in the market, and is not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market rates, operating exposures, and the timing thereof, as well as changes to the Company's wholesale power marketing portfolio during the year. 60 The Company's outstanding long-term debt is fixed rate debt and not subject to interest rate fluctuation. The Company has not historically utilized interest rate swaps or similar hedging arrangements to protect against fluctuations in interest rates. PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The following represents a discussion of legal proceedings that first became a reportable event in the current year or material developments for those legal proceedings previously reported in the Company's 2000 Annual Report on Form 10-K ("Form 10-K"). This discussion should be read in conjunction with Item 3. - Legal Proceedings in the Company's Form 10-K. PVNGS Water Supply Litigation As previously reported, The Company understands that a summons served on APS in 1986 required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons and the rights of the PVNGS participants, including the Company, to the use of groundwater and effluent at PVNGS are potentially at issue in this action. APS, as the PVNGS project manager, filed claims that dispute the court's jurisdiction over the PVNGS participants' groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. APS and other parties have petitioned the United States Supreme Court for review of this decision and the petition was denied. In addition, the Arizona Supreme Court issued a decision affirming the lower court's criteria for solving groundwater claims. APS and other parties filed motions for reconsideration on one aspect of that decision. Those motions have been denied by the Arizona Supreme Court. APS and other parties petitioned the United States Supreme Court for review of the Arizona Supreme Court's decision affirming the lower court's criteria for resolving groundwater claims, and that petition was denied. The Company is unable to predict the outcome of this case. Purported Navajo Environmental Regulation As previously reported, in July 1995 the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the "Acts"). Pursuant to the Acts, the Navajo Nation Environmental Protection Agency is authorized to promulgate regulations covering air quality, drinking water and pesticide activities, including those that occur at Four Corners. In February 1998, the EPA issued regulations specifying provisions of the Clean Air Act for which it is appropriate to treat Indian tribes in the same manner as states. The EPA indicated that it believes that the Clean Air Act generally would supersede pre-existing binding agreements that may limit the scope of tribal authority over reservations. In February 1999, the EPA issued regulations under which Federal operating permits for stationary sources in Indian Country can be issued pursuant to Title V of the Clean Air Act. The regulations rely on authority contained in an earlier rule in which the EPA outlined treatment of tribes as states under the Clean Air Act. The Company as a participant in the Four Corners 61 Power Plant ("Four Corners") and as operating agent and joint owner of San Juan Generating Station, and owners of other facilities located on other reservations located in New Mexico, has filed appeals to contest the EPA's authority under the regulations. On July 14, 2000, the DC Circuit issued its opinion denying the Company's motion for rehearing of the decision denying claims concerning the interpretation by EPA of tribal authority under the Clean Air Act. The Company filed a petition for writ of certiorari to the United States Supreme Court, which was denied on April 16, 2001. The Company does not expect any immediate impacts as a result of this decision but will continue to monitor developments with the Navajo Nation and EPA. The appeal of the Title V regulations is still pending. The Company cannot predict the outcome of these proceedings or any subsequent determinations by the EPA. There can be no assurance that the outcome of these matters will not have a material impact on the results of operations and financial position of the Company. Royalty Claims Natural Gas Royalties Qui Tam Litigation As previously reported, the Company is defending a False Claims Act compliant (MDL Docket Number 1293) in the Federal District Court for the District of Wyoming, which alleged improper measurement of natural gas from federal and tribal lands and consequently, underpayment of royalties to the federal government. On May 18, 2001, the Wyoming court denied defendants' motion to dismiss the complaint. A motion has been filed by the plaintiff asking the court to hold a conference to schedule further procedural steps, but no such conference has yet been set. The Company is vigorously defending this lawsuit and is unable to estimate the potential liability, if any, or to predict the ultimate outcome of this lawsuit. Quinque Operating Co. et al. v Gas Pipelines, et al As previously reported, a class action lawsuit against 233 defendants, including the Company, captioned Quinque Operating Co. et al. v. Gas Pipelines, et al., C.A. No. 99-CV-30 ("Quinque"), was filed in the state district court for Stevens County, Kansas by representatives of classes of gas producers, royalty owners, overriding royalty owners and working interest owners, alleging that the defendants, all engaged in various aspects of the natural gas industry, mismeasured natural gas and underpaid royalties for gas produced on non-federal and non-tribal lands. The claims for relief are based on state law, including a breach of contract claim. They are factually similar, however, to the allegations of "In re: Natural Gas Royalties Qui Tam Litigation", described in the Company's Form 10-K-Part I-Item 3. Legal Proceedings - "Royalty Claims". The Quinque complaint seeks actual damages, treble damages, costs and attorneys fees, among other relief. The Quinque case was removed to the United States District Court for the District of Kansas and transferred to the United States District Court for Wyoming ("Wyoming Court") to consolidate it with the In re: Natural Gas Royalties Qui Tam Litigation. Plaintiffs filed objections to the motions to consolidate and transfer and moved to remand the case to state court. On January 12, 2001, the Wyoming Court granted Plaintiffs motion to remand the case back to Kansas State Court. A motion to reconsider has been denied. This case has been 62 remanded to the state court in Kansas, where, on June 8, 2001, a second amended petition was filed and served on the Company. The second amended petition is similar to the earlier petitions. A case management order has been entered that provides that the court will consider motions to dismiss on personal jurisdiction and other grounds and whether to allow the case to proceed as a class action before any discovery on the merits commences. The schedule, as recently revised, calls for the resolution of these preliminary issues by the spring of 2002. Discovery on jurisdictional and class certification issues only has commenced. The Company is vigorously defending this lawsuit and is unable to estimate the potential liability, if any, or to predict the ultimate outcome of this lawsuit. KAFB Contract The Company reported previously that the DOE had entered into an agency agreement with WAPA on behalf of KAFB, one of the Company's largest retail electric customers, by which WAPA would competitively procure power for KAFB. The proposed wholesale power procurement was to begin at the expiration of KAFB's power service contract with the Company in December 1999. On May 4, 1999, the Company received a request for network transmission service from WAPA pursuant to Section 211 of the Federal Power Act to facilitate the delivery of wholesale power to KAFB over the Company's transmission system. The Company denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB is and will continue to be a retail customer until the effective date KAFB can elect customer choice service under the provisions of the Restructuring Act of 1999. The Company also cited several provisions of Federal law that prohibit the provision of such service to WAPA. On October 1, 1999, WAPA filed a petition at the FERC requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA under the Company's Open Access Transmission Tariff on behalf of DOE and several other entities located on KAFB. The petition claimed KAFB is a wholesale customer of the Company, not a retail customer. By order entered on April 13, 2001 the FERC denied the WAPA transmission application. The FERC order determined, among other things, that WAPA had failed to demonstrate that its sales to DOE are sales for resale and also that WAPA failed to qualify for certain claimed exemptions under the Federal Power Act that would have entitled it to provide expanded service to DOE. WAPA requested rehearing of FERC's April 13, 2001 order. In a proposed order issued on June 13, 2001, FERC granted WAPA's request for rehearing. FERC determined that WAPA qualified for an exemption to the prohibition against an order requiring service to retail customers and that FERC therefore could require the Company to provide the requested service. FERC directed the Company and WAPA to engage in negotiations concerning terms and conditions of service, including compensation. In the event agreement is not reached, the Company and WAPA are directed to file briefs and provide information so that the FERC can establish interim or final rates for service. The June 13 order is a "proposed" order, and is not subject to requests for rehearing or judicial review. FERC may establish terms and conditions in a "final" order that would be subject to requests for rehearing and to judicial review. The Company is evaluating its legal options in relation to the "proposed" order or any resulting "final" order. In a separate but related proceeding, the Company and the United States Executive Agencies on behalf of KAFB are involved in a PRC case regarding a dispute over the specific Company tariff language under which the Company provides retail service to KAFB. The Company agreed to continue to provide service to KAFB after expiration of the contract, pending resolution of all relevant issues. The parties are pursuing informal settlement discussions with regard to this case. The Company intends to vigorously defend its position at the PRC. 64 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Annual Meeting The annual meeting of shareholders was held on July 3, 2001. The matters voted on at the meeting and the results were as follows: The election of the following three nominees to serve as directors until the annual meeting of shareholders in 2004, or until their successors are duly elected and qualified, as follows: Votes Against Director Votes For Or Withheld -------- --------- ----------- John T. Ackerman 34,583,909 320,989 Joyce A. Godwin 34,608,635 296,263 Manuel Lujan, Jr. 34,580,689 324,209 As reported in the Definitive 14A Proxy Statement filed May 24, 2001, the name of each other director whose term of office as director continues after the meeting is as follows: Robert G. Armstrong Benjamin F. Montoya Theodore F. Patlovich Robert M. Price Paul F. Roth Jeffry E. Sterba The approval of amendments to the Director Retainer Plan as follows: Votes Against Votes for or Withheld Abstentions ----------- ------------- ----------- 31,058,761 3,506,521 339,616 The approval of an amendment to the PNM Resources, Inc. Omnibus Performance Equity Plan as follows: Votes Against Votes for or Withheld Abstentions ----------- ------------- ----------- 32,835,839 1,777,818 291,240 The ratification of amendments to the Articles of Incorporation of the proposed holding company as follows: Votes Against Votes for or Withheld Abstentions ---------- ------------ ----------- 34,461,955 264,284 178,659 65 The approval of the selection by the Company's board of directors of Arthur Andersen LLP as independent auditors for the fiscal year ending December 31, 2001, was voted on, as follows: Votes Against Votes for or Withheld Abstentions --------- ----------- ----------- 34,623,121 196,449 85,328 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits: NONE. b. Reports on Form 8-K: Report dated and filed May 18, 2001 reporting the Company's Comparative Operating Statistics for the month of April 2001 and 2000 and the year ended April 30, 2001 and 2000. Report dated and filed May 25, 2001 reporting the Kansas Corporation Commission (the "KCC") supplemented its May 8, 2000 order. Report dated and filed June 1, 2001 reporting the Company filed a registration statement on Form S-8 registering 100,000 shares of its common stock for the Company Master Employee Savings Plan and Trust. Report dated and filed June 14, 2001 reporting the Company's Comparative Operating Statistics for the month of May 2001 and 2000 and the year ended May 31, 2001 and 2000. Report dated and filed July 6, 2001 reporting the Company to serve Texas-New Mexico power with long-term power sale. Report dated and filed July 6, 2001 reporting the annual meeting speech of the Company's Chairman, President and Chief Executive Officer, Jeff Sterba delivered at the Company's annual meeting held on July 3, 2001 and the Company's press release summarizing the annual meeting speech. Report dated and filed July 13, 2001 reporting the Company's Comparative Operating Statistics for the month of June 2001 and 2000 and the year ended June 30, 2001 and 2000. Report dated and filed July 16, 2001 reporting the Company announces new date for Second Quarter 2001 Earnings Conference Call. Report dated and filed July 18, 2001 reporting the Company declares Common Stock Dividend. 66 Report dated and filed July 18, 2001 reporting the Company's Quarter Ended June 30, 2001 Earnings Announcement and Consolidated Statements of Earnings - Three, Six and Twelve Months Ended June 30, 2001 and 2000. Report dated and filed July 24, 2001 reporting the Company denies report it is "Reconsidering" Western Resources Acquisition. Report dated and filed July 30, 2001 reporting the Company asks New Mexico regulators to reconsider Holding Company order. Report dated and filed August 10, 2001 reporting the Company Comparative Operating Statistics for the month of July 2001 and 2000 and the year ended July 30, 2001 and 2000. 67 Signature - --------- Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW MEXICO ----------------------------------------------- (Registrant) Date: August 14, 2001 /s/ John R. Loyack ----------------------------------------------- John R. Loyack Vice President, Corporate Controller and Chief Accounting Officer (Officer duly authorized to sign this report) 68 -----END PRIVACY-ENHANCED MESSAGE-----