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