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 September 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 November 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 Nine Months Ended September 30 2001 and 2000...... 4
Consolidated Balance Sheets -
September 30, 2001 and December 31, 2000........................... 5
Consolidated Statements of Cash Flows -
Nine Months Ended September 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............. 27
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK............................................... 67
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS............................................ 68
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................. 73
Signature .......................................................... 75
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
September 30, 2001, and the related condensed consolidated statements of
earnings for the three-month and nine-month periods ended September 30, 2001 and
2000, and the condensed consolidated statements of cash flows for the nine-month
periods ended September 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
November 13, 2001
3
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- ------------------------
2001 2000 2001 2000
----------- ------------ ---------- -------------
(thousands, except per share amounts)
Operating Revenues:
Electric......................................... $ 582,066 $ 444,101 $ 1,704,390 $ 943,681
Gas.............................................. 39,649 55,133 318,670 204,193
Unregulated businesses........................... 180 243 1,456 1,935
----------- ----------- ----------- -----------
Total operating revenues....................... 621,895 499,477 2,024,516 1,149,809
----------- ----------- ----------- -----------
Operating Expenses:
Cost of energy sold.............................. 429,965 316,519 1,360,904 664,636
Energy production costs.......................... 36,224 32,854 109,128 104,402
Administrative and general....................... 39,241 36,926 117,494 102,683
Depreciation and amortization.................... 24,194 23,022 72,343 69,664
Transmission and distribution costs.............. 18,402 14,537 48,760 44,614
Taxes, other than income taxes................... 6,380 9,103 21,436 25,234
Income taxes..................................... 20,067 19,064 89,182 32,523
----------- ------------- ------------ ------------
Total operating expenses..................... 574,473 452,025 1,819,247 1,043,756
----------- ------------- ------------ ------------
Operating income............................... 47,422 47,452 205,269 106,053
----------- ------------- ------------ ------------
Other Income and Deductions:
Other............................................ 3,310 26,302 (14,196) 49,487
Income taxes..................................... (2,277) (10,733) 3,275 (19,660)
----------- ------------- ------------ ------------
Net other income and deductions................ 1,033 15,569 (10,921) 29,827
----------- ------------- ------------ ------------
Income before interest charges................. 48,455 63,021 194,348 135,880
----------- ------------- ------------ ------------
Interest Charges:
Interest on long-term debt....................... 15,683 15,683 47,049 47,140
Other interest charges........................... (3) 425 1,375 1,889
----------- ------------- ------------ ------------
Interest charges............................... 15,680 16,108 48,424 49,029
----------- ------------- ------------ ------------
Net Earnings....................................... 32,775 46,913 145,924 86,851
Preferred Stock Dividend Requirements.............. 147 147 440 440
----------- ------------- ------------ ------------
Net Earnings Applicable to Common Stock............ $ 32,628 $ 46,766 $ 145,484 $ 86,411
=========== ============= ============ ============
Net Earnings per Common Share:
Basic............................................ $ 0.83 $ 1.19 $ 3.72 $ 2.18
=========== ============= ============ ============
Diluted.......................................... $ 0.82 $ 1.18 $ 3.66 $ 2.17
=========== ============= ============ ============
Dividends Paid per Share of Common Stock........... $ 0.20 $ 0.20 $ 0.60 $ 0.60
=========== ============= ============ ============
The accompanying notes are an integral part of these financial statements.
4
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2001 2000
-------------- --------------
Unaudited)
ASSETS (In thousands)
- ------
Utility Plant:
Electric plant in service......................................... $2,093,176 $2,030,813
Gas plant in service.............................................. 562,554 553,755
Common plant in service and plant held for future use............. 37,655 36,678
-------------- --------------
2,693,385 2,621,246
Less accumulated depreciation and amortization.................... 1,237,238 1,153,377
-------------- --------------
1,456,147 1,467,869
Construction work and progress.................................... 231,128 123,653
Nuclear fuel, net of accumulated amortization of
$21,246 and $19,081............................................ 25,303 25,784
-------------- --------------
Net utility plant............................................... 1,712,578 1,617,306
-------------- --------------
Other Property and Investments:
Other investments................................................. 439,022 479,821
Non-utility property, net of accumulated depreciation of
$1,538 and $1,644............................................. 1,826 3,666
-------------- --------------
Total other property and investments............................ 440,848 483,487
-------------- --------------
Current Assets:
Cash and cash equivalents......................................... 222,605 107,691
Accounts receivables, net of allowance for uncollectible
accounts of $8,317 and $8,963................................. 262,238 242,742
Other receivables................................................. 44,963 64,857
Inventories....................................................... 38,750 36,091
Regulatory assets................................................. 1,381 47,604
Other current assets.............................................. 48,018 11,417
-------------- --------------
Total current assets............................................ 617,955 510,402
-------------- --------------
Deferred Charges:
Regulatory assets................................................. 207,673 226,849
Prepaid benefit costs............................................. 22,948 18,116
Other deferred charges............................................ 20,554 38,073
-------------- --------------
Total deferred charges.......................................... 251,175 283,038
-------------- --------------
$3,022,556 $2,894,233
============== ==============
5
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2001 2000
-------------- --------------
Unaudited)
CAPITALIZATION AND OTHER LIABILITIES (In thousands)
- ------------------------------------
Capitalization:
Common stockholders' equity:
Common stock......................................................... $ 195,589 $ 195,589
Additional paid-in capital........................................... 428,660 432,222
Accumulated other comprehensive income, net of tax................... (2,986) (27)
Retained earnings.................................................... 418,850 296,843
-------------- --------------
Total common stockholders' equity................................. 1,040,113 924,627
Minority interest....................................................... 11,651 12,211
Cumulative preferred stock without mandatory
redemption requirements............................................ 12,800 12,800
Long-term debt, less current maturities................................. 953,870 953,823
-------------- --------------
Total capitalization.............................................. 2,018,434 1,903,461
-------------- --------------
urrent Liabilities:
Accounts payable........................................................ 206,277 257,991
Accrued interest and taxes.............................................. 116,066 36,889
Other current liabilities............................................... 113,262 67,758
-------------- --------------
Total current liabilities......................................... 435,605 362,638
-------------- --------------
Deferred Credits:
Accumulated deferred income taxes......................................... 113,981 166,249
Accumulated deferred investment tax credits............................... 45,499 47,853
Regulatory liabilities.................................................... 56,762 65,552
Regulatory liabilities related to accumulated deferred income tax......... 14,144 20,696
Accrued postretirement benefit costs...................................... 22,226 11,899
Other deferred credits.................................................... 315,905 315,885
-------------- --------------
Total deferred credits................................................. 568,517 628,134
-------------- --------------
$3,022,556 $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)
Nine Months Ended
September 30,
------------------------------
2001 2000
------------- -------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings....................................................... $ 145,924 $ 86,851
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization.................................. 80,086 77,728
Other, net..................................................... 15,413 (13,031)
Changes in certain assets and liabilities:
Accounts receivables......................................... (19,497) (69,350)
Other assets................................................. 36,490 40,416
Accounts payable............................................. (51,714) 20,997
Accrued taxes................................................ 80,907 23,768
Other liabilities............................................ 9,251 2,884
------------- -------------
Net cash flows provided from operating activities............ 296,860 170,263
------------- -------------
Cash Flows From Investing Activities:
Utility plant additions............................................ (165,127) (97,738)
Return on PVNGS lease obligation bonds............................. 16,674 16,668
Other investing.................................................... (5,440) (5,006)
------------- -------------
Net cash flows used from investing activities................ (153,893) (86,076)
------------- -------------
Cash Flows From Financing Activities:
Repayments......................................................... - (32,800)
Common stock repurchase............................................ - (27,875)
Exercise of employee stock options................................. (3,589) (4)
Dividends paid..................................................... (23,905) (24,275)
Other financing.................................................... (559) (559)
------------- -------------
Net cash flows used in financing activities.................. (28,053) (85,513)
------------- -------------
Increase in Cash and Cash Equivalents................................ 114,914 (1,326)
Beginning of Period.................................................. 107,691 120,399
------------- -------------
End of Period........................................................ $222,605 $119,073
============= =============
Supplemental Cash Flow Disclosures:
Interest paid...................................................... $ 48,298 $ 50,393
============= =============
Income taxes paid, net ............................................ $ 56,150 $ 25,922
============= =============
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 September 30, 2001 and
December 31, 2000, the consolidated results of its operations for the three
months and nine months ended September 30, 2001 and 2000 and the consolidated
statements of cash flows for the nine months ended September 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.
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
(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 September 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. In July 2001, the Board of Directors of Avistar decided to
wind down all operations except for Avistar's Reliadigm business unit, which
provides maintenance solutions to the electric power industry. Avistar had
previously divested itself of its Energy Partners business unit and liquidated
Axon Field Services and Pathways Integration. In addition, the transfer of the
Sangre de Cristo Water Company operations to the City of Santa Fe was completed
in the third quarter. All remaining non-Reliadigm investments were written-off
with the exception of Avistar's investment in Nth Power, an energy related
venture capital fund. In the third quarter
9
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2) Nature of Business and Segment Information (Continued)
of 2001, the Company recorded a related charge of $4.2 million. The Company had
previously taken charges of $13.0 million to reflect these activities and the
impairment of its Avistar investments.
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 supply service and energy-related service assets to be
deregulated from distribution and transmission service assets that would
continue to be regulated. 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 required that the PRC approve a
holding company, subject to terms and conditions in the public interest, without
corporate separation of supply service and energy-related service assets from
distribution and transmission service assets, 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.
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
10
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2) Nature of Business and Segment Information (Continued)
on a rolling four quarter basis and imposes certain regulatory requirements
regarding merchant generation plants. The Company believes that certain
conditions imposed by the PRC order are unlawful 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 did not act on the Company's request,
and the request was deemed denied on August 16, 2001. Despite this adverse
ruling, the Company plans to proceed with its plans to activate PNM Resources
and complete the mandatory share exchange. At the same time, the Company will
continue with its efforts to minimize the adverse effects of the order. On
September 14, 2001, the Company asked the New Mexico Supreme Court to review the
holding company order. The Company believes the PRC exceeded its jurisdiction
and placed certain conditions on the new corporate structure that the Company
believes are unlawful. The Attorney General has filed a cross-appeal. The
Company is unable to predict the outcome of its appeal or cross-appeal. In
filings with the PRC, Staff and other parties have raised the issue whether the
Company should be allowed to form the holding company pending appeal. The
Company has filed its response and intends to vigorously defend its right to
form the holding company pending appeal. The Company is unable to predict what
action the PRC may take regarding this issue.
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 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, that occurred in 2000 and early 2001, as well as the related
increased prices for power elsewhere in the Western United States and concerns
over inadequate capacity. 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.
11
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2) Nature of Business and Segment Information (Continued)
Summarized financial information by business segment for the three
months ended September 30, 2001 and 2000 is as follows:
Utility
------------------------------- Generation Unregulated
Electric Gas Total and Trading and Other Consolidated
-------- --- ------ ----------- ------------ ------------
(In thousands)
2001:
Operating revenues:
External customers............. $153,535 $39,649 $193,184 $428,531 $ 180 $621,895
Intersegment revenues.......... 177 - 177 95,413 - 95,590
Depreciation and amortization..... 8,220 5,400 13,620 10,564 10 24,194
Interest income................... 555 126 681 9,841 1,585 12,107
Interest charges.................. 5,610 2,423 8,033 4,470 3,177 15,680
Operating income (loss)........... 18,284 650 18,934 33,223 (4,735) 47,422
Income tax expense (benefit)
from continuing operations...... 8,186 (1,390) 6,796 21,794 (6,246) 22,344
Segment net income (loss)......... 12,490 (2,120) 10,370 33,256 (10,851) 32,775
Total assets...................... 799,607 466,550 1,266,157 1,522,354 297,567 3,086,078
Gross property additions.......... 18,577 11,378 29,955 14,856 4,375 49,186
2000:
Operating revenues:
External customers............. $149,970 $ 55,133 $205,103 $294,131 $ 243 $499,477
Intersegment revenues.......... 177 - 177 90,638 - 90,815
Depreciation and amortization..... 7,856 4,989 12,845 10,170 7 23,022
Interest income................... 329 137 466 10,175 1,340 11,981
Interest charges.................. 4,342 2,645 6,987 9,013 108 16,108
Operating income (loss)........... 19,092 2,863 21,955 32,321 (6,824) 47,452
Income tax expense (benefit)
from continuing operations...... 9,464 2,689 12,153 23,114 (5,470) 29,797
Segment net income (loss)......... 15,553 3,922 19,475 37,564 (10,126) 46,913
Total assets...................... 768,912 419,579 1,188,491 1,447,513 156,176 2,792,180
Gross property additions.......... 16,406 13,350 29,756 17,605 (511) 46,850
12
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2) Nature of Business and Segment Information (Continued)
Summarized financial information by business segment for the nine
months ended September 30, 2001 and 2000 is as follows:
Utility
------------------------------ Generation Unregulated
Electric Gas Total and Trading and Other Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2001:
Operating revenues:
External customers............. $424,249 $318,670 $742,919 $1,280,141 $ 1,456 $2,024,516
Intersegment revenues.......... 530 - 530 259,726 - 260,256
Depreciation and amortization..... 24,311 16,023 40,334 31,981 28 72,343
Interest income................... 1,555 677 2,232 29,546 5,467 37,245
Interest charges.................. 14,163 8,365 22,528 22,661 3,235 48,424
Operating income (loss)........... 48,674 15,281 63,955 151,906 (10,592) 205,269
Income tax expense (benefit)
from continuing operations...... 21,883 4,560 26,443 88,667 (29,203) 85,907
Segment net income (loss)......... 33,393 6,959 40,352 135,302 (29,730) 145,924
Total assets...................... 799,607 466,550 1,266,157 1,522,354 297,567 3,086,078
Gross property additions.......... 47,082 28,836 75,918 78,674 10,534 165,126
2000:
Operating revenues:
External customers............. $406,034 $204,193 $610,227 $537,647 $ 1,935 $1,149,809
Intersegment revenues.......... 530 - 530 245,330 - 245,860
Depreciation and amortization..... 23,903 14,870 38,773 30,873 18 69,664
Interest income................... 722 384 1,106 29,697 4,776 35,579
Interest charges.................. 13,195 8,380 21,575 27,041 413 49,029
Operating income (loss)........... 48,729 12,942 61,671 62,610 (18,228) 106,053
Income tax expense (benefit)
from continuing operations...... 22,586 5,989 28,575 35,596 (11,988) 52,183
Segment net income (loss)......... 36,090 8,586 44,676 61,612 (19,437) 86,851
Total assets...................... 768,912 419,579 1,188,491 1,447,513 156,176 2,792,180
Gross property additions.......... 38,343 24,562 62,905 34,821 2,342 100,068
13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(3) Comprehensive Income
Changes in comprehensive income are as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- ------------------------
2001 2000 2001 2000
------------ ------------ ------------ -----------
(In thousands)
Net Earnings............................................ $32,775 $46,913 $145,924 $86,851
------------ ------------ ------------ -----------
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses)
arising during the period........................ (1,459) 695 (885) 2,081
Less reclassification adjustment for gains (losses)... 341 (1,013) (693) (2,961)
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.................... (17,930) (8,309)
- -
------------ ------------ ------------ -----------
Total Other Comprehensive Income (Loss).............. (19,048) (318) (2,959) (880)
------------ ------------ ------------ -----------
Total Comprehensive Income.............................. $13,727 $46,595 $142,965 $85,971
============ ============ ============ ===========
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,
14
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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
receivable with its largest counterparty as of September 30, 2001 was $36.5
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 cost and financial
impacts of all hedge gains and losses 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.
In 2001, the Company began a hedge program to protect its natural gas
customers from price risk during the 2001-2002 heating season through the use of
financial hedging tools. As of September 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. The
Company intends to continue this program for the 2001-2002 heating season to the
extent it continues to meet the guidelines of the PRC.
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
15
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(4) Financial Instruments (Continued)
for a portion of its anticipated natural gas needs in the third and fourth
quarters. As of September 30, 2001, the open futures contracts lock in the
Company's natural gas purchase prices at $2.12 to $5.90 per MMBTU and have a
notional principal of $3.9 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 nine months ended September 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 enter 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 September 30, 2001, the Company's Generation and Trading
Operations settled trading contracts for the sale of electricity that generated
$70.7 million of electric revenues by delivering 610 million KWh. The Company
purchased $69.5 million or 591 million KWh of electricity to support these
contractual sales and other open market sales opportunities.
As of September 30, 2001, the Company's Generation and Trading
Operations had open trading contract positions to buy $89.8 million and to sell
$47.6 million of electricity. At September 30, 2001, the Company had a gross
mark-to-market gain (asset position) on these trading contracts of $24.7 million
and a gross mark-to-market loss (liability position) of $56.2 million, with net
mark-to-market losses of $31.5 million. The mark-to-market valuation is
recognized in earnings each period.
In addition, the Company's Generation and Trading Operations enter 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
September 30, 2001, the Company had open forward positions classified as normal
sales of electricity of $63.2 million and normal purchases of electricity of
$38.0 million.
16
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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
September 30, 2001, were forward purchase contracts for the purchase of electric
power for forecasted jurisdictional use during planned outages in 2001 and
certain other 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 September 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.
17
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 September 30 (in thousands except per share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
----------- ----------- ----------- -----------
Basic:
Net Earnings............................................ $ 32,775 $ 46,913 $145,924 $ 86,851
Preferred Stock Dividend Requirements................... 147 147 440 440
----------- ----------- ----------- -----------
Net Earnings Applicable to Common Stock................. $ 32,628 $ 46,766 $145,484 $ 86,411
=========== =========== =========== ===========
Average Number of Common Shares Outstanding............. 39,118 39,363 39,118 39,623
=========== =========== =========== ===========
et Earnings per Common Share (Basic).................... $ 0.83 $ 1.19 $ 3.72 $ 2.18
=========== =========== =========== ===========
Diluted:
Net Earnings Applicable to Common Stock
Used in basic calculation............................. $ 32,628 $ 46,766 $145,484 $ 86,411
=========== =========== =========== ===========
Average Number of Common Shares Outstanding............. 39,118 39,363 39,118 39,623
Diluted Effect of Common Stock Equivalents (a).......... 630 288 653 125
----------- ----------- ----------- -----------
Average Common and Common Equivalent Shares
Outstanding........................................... 39,748 39,651 39,771 39,748
=========== =========== =========== ===========
Net Earnings per Share of Common Stock (Diluted)........ $ 0.82 $ 1.18 $ 3.66 $ 2.17
=========== =========== =========== ===========
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out-of-the-money options of 92,949 and 140,448 for the three
months and nine months ended September 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.
18
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(6) Commitments and Contingencies (Continued)
Construction Commitment
The Company has committed to purchase five combustion turbines totaling
$151.3 million. The turbines are for three planned power generation plants with
a combined capacity of 657 MWs. The plants estimated cost of construction is
approximately $400.3 million. The Company has expended $89.4 million as of
September 30, 2001. In November, 2001, the Company plans to break ground for a
new 135 MW single cycle gas turbine plant on a site in Southern New Mexico.
Currently the Company plans to expand the facility to 540 MW by 2003. Contracts
have not been finalized on the remaining planned construction. 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. The Company also is
cooperating with an investigation of the incident by the New Mexico Public
Regulation Commission's Pipeline Safety Bureau. 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
19
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(6) Commitments and Contingencies (Continued)
for the nine months ended September 30, 2001 and $2 million for the year ended
December 31, 2000 in anticipation of higher than normal delinquency rates. Based
upon information available at September 30, 2001, the Company believes the
allowance for doubtful accounts of $8.3 million is adequate for management's
estimate of potential uncollectible accounts.
The following is a summary of the allowance for doubtful accounts
during the nine months ended September 30, 2001 and the year ended December 31,
2000:
September 30, December 31,
2001 2000
------------- ------------
Allowance for doubtful accounts, beginning
of year.......................................... $ 8,963 $ 12,504
Bad debt accrual................................... 9,980
3,373
Less: Write-off (adjustments) of uncollectible
Accounts......................................... 13,521
4,019
------------ ------------
Allowance for doubtful accounts, end of period .... $ 8,317 $ 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
20
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(6) Commitments and Contingencies (Continued)
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 $4.8 million per year. This insurance coverage is subject to
certain policy conditions and exclusions.
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 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 September 30, 2001 was approximately $48 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 other claims and lawsuits pending against the Company
and certain of its subsidiaries, in addition to the matters discussed above. 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 of these other matters not
discussed in detail above will have a material adverse effect on its financial
condition or results of operations.
21
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 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.
For the nine months ended September 30, 2001, the Company spent $1.2
million for remediation. The majority of the September 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) Western Resources 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
22
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(8) Western Resources Acquisition (Continued)
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). On October 12, 2001, the Company filed suit
in the Supreme Court of New York ("NY Court") asking the NY Court to find that
it is impossible to complete the proposed transaction under the original terms.
The Company also asked the NY Court to rule that an electric rate reduction
mandated by the KCC is a material adverse effect removing the obligation to
effect the transaction. Western Resources' response to the Complaint is due on
November 26, 2001.
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 split off to Western Resources' shareholders,
prior to the acquisition of Western's electric utility businesses by the
Company.
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. The portion of each
Western Resources share not converted into Westar Industries stock in connection
with the split off will be exchanged for a fraction of a share of the new
holding 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 Industries have been given a
limited incentive to reduce Western Resources' net debt balance prior to the
consummation of the transaction by selling non-utility assets or through certain
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 $641 million of additional equity infusions and existing
intercompany receivables 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.
23
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(8) Western Resources Acquisition (Continued)
In February 2001, Westar Industries 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 Industries.
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 reported results 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.
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 would be 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 Resources
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 Resources to file a financial plan
within 90 days to restore Western Resources' financial ratings to the investment
grade level of similarly situated electric public utilities. Western Resources
filed for reconsideration of the order. On October 3, 2001, the KCC issued its
order on reconsideration of
24
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(8) Western Resources Acquisition (Continued)
the split-off order, reaffirming its prior order prohibiting the split-off as
presently designed and confirming that a merger would not cure the problems
associated with the split-off. In October 2001, Western Resources filed
petitions for judicial review in the District Court of Shawnee County, Kansas,
of the split-off order and the reconsideration order.
On July 25, 2001, the KCC issued an order reducing the rates of Western
Resources electric utilities by the net amount of $22.7 million annually.
Western Resources had sought a combined increase of approximately $151 million
annually. Western Resources filed for reconsideration of the order and on
September 5, 2001, the KCC slightly increased rates resulting in a revised net
reduction of approximately $15.7 million annually. Western Resources and other
parties in the case filed for reconsideration of the KCC's revised rate order.
On October 11, 2001, the KCC issued an order denying all petitions for
reconsideration of the revised rate order.
On July 30, 2001, the Company and Western Resources issued a joint
release stating that the transaction as presently designed would be difficult to
complete if the KCC orders remain in effect. The release announced that the
Company and Western Resources would begin discussions on how to modify the
transaction to make it possible to obtain necessary regulatory approvals.
On August 13, 2001, the Company announced that Western Resources had
decided to discontinue the talks about modifying the transaction and desired to
attempt to pursue completion 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 Resources has advised
the Company that it does not believe that the rate case order results in a
material adverse effect.
Western Resources has requested that the Company file for regulatory
approvals of the transaction as presently designed, despite the fact that the
transaction requires the split-off already determined to be unlawful by the KCC.
As a result of the disagreement over the viability of the transaction as
presently designed, the Company filed suit on October 12, 2001, in New York
state court seeking declarations that the transaction could not be accomplished
as presently designed due to the KCC's determination that the split-off
condition of the transaction is unlawful; that the Company is not obligated to
pursue approvals of the transaction as presently designed; that the transaction
is terminated effective December 31, 2001, without an automatic extension; and
that the KCC rate case order constitutes a material adverse effect under the
agreement. The Company also seeks monetary damages for breach of contract
because Western Resources represented and warranted that the split-off did not
require approval of the KCC. The Company is unable to predict the outcome of
this proceeding.
25
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(8) Western Resources Acquisition (Continued)
On November 6, 2001, Western Resources filed its financial plan for
restructuring debt pursuant to the KCC's July 20 order. The plan is essentially
comprised of two parts. The first part is stated by Western Resources as being
designed to reduce debt by $100 to $175 million in the next several months by
means of a rights offering of between $8.7 million and $19.1 million Westar
Industries shares to Western Resources shareholders, representing between 10.2%
and 19.9% of outstanding shares of Westar Industries. The second part is stated
by Western Resources as being designed to reduce debt below $1.8 billion over
the next one to three years through the sale by Western Resources of its Westar
Industries common stock or Western Resources shares. The second part would not
take place unless Westar Industries' stock price trades for 45 consecutive
trading days at a price 25% higher than the price necessary to reduce Western
Resources' debt below $1.8 billion. The first part of the plan is acknowledged
by Western Resources to be similar to the split-off ruled unlawful by the KCC
but Western Resources asserts that it has made certain modifications in an
attempt to address concerns raised by the KCC. The Company continues to monitor
the proceedings in Kansas and intends to pursue the litigation in New York State
Court.
(9) New and Proposed Accounting Standards
Statement of Financial Accounting Standards No. 143, Accounting for
Asset Retirement Obligations ("SFAS 143"). In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS 143. The statement requires the
recognition of a liability for legal obligations associated with the retirement
of a tangible long-lived asset that result from the acquisition, construction or
development and/or the normal operation of a long-lived asset. The asset
retirement obligation is required to be recognized at its fair value when
incurred. The cost of the asset retirement obligation is required to be
capitalized by increasing the carrying amount of the related long-lived asset by
the same amount as the liability. This cost must be expensed using a systematic
and rational method over the related asset's useful life. SFAS 143 is effective
for the Company beginning January 1, 2003. The Company is currently assessing
the impact of SFAS 143 and is unable to predict its impact on the Company's
operating results and financial position at this time.
Statement of Financial Accounting Standards No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets ("SFAS 144"). In August 2001, the
FASB issued SFAS 144. The statement amends certain requirements of the
previously issued pronouncement on asset impairment, Statement of Financial
Accounting Standards No. 121 ("SFAS 121"). SFAS 144 removes goodwill from the
scope of SFAS 121, provides for a probability-weighted cash flow estimation
approach for estimating possible future cash flows, and establishes a "primary
asset" approach for a group of assets and liabilities that represents the unit
of accounting to be evaluated for impairment. In addition, SFAS 144 changes the
measurement of long-lived assets to be disposed of by sale, as accounted for by
Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued
operations are no longer measured on a net realizable value basis, and their
future operating losses are no longer recognized before they occur. The Company
does not believe SFAS 144 will have a material effect on its future operating
results or financial position.
26
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, as the context requires, 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. 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.
The following table shows electric sales by customer class:
ELECTRIC SALES
(Megawatt hours)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
------------- ---------- ----------- -----------
Residential........... 593,453 592,187 1,676,271 1,638,633
Commercial............ 931,937 912,951 2,447,231 2,367,363
Industrial............ 425,299 399,364 1,210,266 1,166,295
Other................. 75,751 74,066 182,450 183,088
------------- ---------- ----------- -----------
2,026,440 1,978,568 5,516,218 5,355,379
============= ========== =========== ===========
27
The following table shows electric revenues by customer class:
ELECTRIC REVENUES
(Thousands of dollars)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
------------ ----------- ----------- -----------
Residential............... $ 50,002 $ 50,782 $142,785 $140,582
Commercial................ 68,363 68,574 183,372 179,269
Industrial................ 21,836 20,691 62,161 60,114
Other..................... 13,511 10,100 36,461 26,599
------------ ----------- ----------- -----------
$153,712 $150,147 $424,779 $406,564
============ =========== =========== ===========
Average customers......... 378,336 369,063 376,297 367,400
============ =========== =========== ===========
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
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.
28
The following table shows gas throughput by customer class:
GAS THROUGHPUT
(Thousands of decatherms)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
---------- ---------- ---------- ----------
Residential........... 2,270 2,240 18,357 17,081
Commercial............ 1,242 1,049 6,867 5,862
Industrial............ 144 2,316 3,665 3,641
Transportation*....... 16,842 14,905 41,243 34,579
Other................. 763 1,593 3,541 5,651
---------- ---------- ---------- ----------
21,261 22,103 73,673 66,814
========== ========== ========== ==========
The following table shows gas revenues by customer:
GAS REVENUES
(Thousands of dollars)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
---------- ---------- ----------- -----------
Residential............... $21,709 $24,084 $ 188,113 $ 117,383
Commercial................ 6,711 7,041 56,375 31,823
Industrial................ 623 11,726 26,541 16,404
Transportation*........... 6,025 3,651 16,437 10,582
Other..................... 4,581 8,631 31,204 28,001
---------- ---------- ----------- -----------
$39,649 $55,133 $ 318,670 $ 204,193
========== ========== =========== ===========
Average customers......... 441,557 426,627 442,982 428,384
========== ========== =========== ===========
*Customer-owned gas.
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.
29
The following table shows sales by customer class:
GENERATION AND TRADING SALES BY MARKET
(Megawatt hours)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
------------ ------------ ------------ -------------
Intersegment sales.................. 2,026,439 1,978,568 5,516,218 5,355,379
Firm-requirement wholesale.......... 165,642 114,340 441,376 209,096
Other contracted off-system sales... 1,977,917 2,149,539 5,483,401 5,664,280
Economy energy sales................ 1,373,454 1,029,641 3,901,723 3,729,391
------------ ------------ ------------ -------------
5,543,452 5,272,088 15,342,718 14,958,146
============ ============ ============ =============
The following table shows revenues by customer class:
GENERATION AND TRADING REVENUES BY MARKET
(Thousands of dollars)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
------------- ----------- -------------- ------------
Intersegment revenues..................... $ 95,413 $ 90,638 $ 259,726 $ 245,330
Firm-requirement wholesale................ 8,663 5,952 16,026 9,577
Other contracted off-system revenues...... 362,729 149,979 803,620 278,484
Economy energy sales...................... 60,137 123,570 486,348 246,195
Other*.................................... (2,998) 14,630 (25,853) 3,391
------------- ----------- -------------- ------------
$ 523,944 $384,769 $ 1,539,867 $ 782,977
============= =========== ============== ============
*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
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 September 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.
30
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 $50 million
in Avistar and has no amounts outstanding under the reciprocal loan agreement.
In July 2001, the Board of Directors of Avistar decided to wind down
all operations except for Avistar's Reliadigm business unit, which provides
maintenance solutions to the electric power industry. Avistar had previously
divested itself of its Energy Partners business unit and liquidated Axon Field
services and Pathways Integration. In addition the transfer of the Sangre de
Cristo Water Company operations to the City of Santa Fe was completed in the
third quarter. All remaining non-Reliadigm investments were written-off with the
exception of Avistar's investment in Nth Power, an energy related venture
capital fund. In the third quarter of 2001, the Company recorded a related
charge of $4.2 million. The Company had previously taken charges of $13.0
million to reflect these activities and the impairment of its Avistar
investments.
WESTERN RESOURCES 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. On October 12, 2001, the
Company filed suit in the Supreme Court for New York County, New York ("NY
Court") asking the NY Court to find that it is impossible to complete the
proposed transaction under the original terms. The Company also asked the NY
Court to rule that an electric rate reduction mandated by the KCC is a material
adverse effect removing the obligations to effect the transaction. (See "Other
Issues Facing The Company - Proposed Acquisition of Western Resources Electric
Operations" below).
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 supply service and energy-related service assets from
distribution and transmission service assets. 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.
31
The amendments to the Restructuring Act required that the PRC approve a
holding company, subject to terms and conditions in the public interest, without
corporate separation of supply service and energy-related service assets from
distribution and transmission service assets, by July 1, 2001. In addition, the
amendments allow utilities to engage in unregulated power generation business
activities until corporate separation is implemented (see "Other Issues Facing
the Company - Merchant Plant Filing.") 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.
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 basis
and imposes certain regulatory requirements regarding merchant generation
plants. The Company believes that certain conditions imposed by the PRC order
are unlawful 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 did not act on the Company's request,
and the request was deemed denied on August 16, 2001. Despite this adverse
ruling, the Company plans to proceed with its plans to activate PNM Resources
and complete the mandatory share exchange. At the same time, the Company will
continue with its efforts to minimize the adverse effects of the order. On
September 14, 2001, the Company asked the New Mexico Supreme Court to review the
holding company order. The Company believes the PRC exceeded its jurisdiction
and placed certain conditions on the new corporate structure that the Company
believes are unlawful. The Attorney General has filed a cross-appeal. The
Company is unable to predict the outcome of its appeal or cross-appeal. In
filings with the PRC, the Staff and other parties raised the issue of whether
the Company should be allowed to form the holding company pending appeal. The
Company has filed its response and intends to vigorously defend its right to
form the holding company pending appeal. The Company is unable to predict what
action the PRC may take regarding this issue.
32
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 prior to open access with minimum regulatory approvals. These
new plants will be excluded from utility rates under the provisions of the law.
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 $1.3 billion 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 $223
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, from time to time, 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. In August 2001, the FERC issued a
series of Orders requiring existing independent system operators and developing
RTOs in the Eastern United States to enter into mediation to form a single RTO
in the Northeast and a second in the Southeast. The FERC expressed the desire
that four RTO's be formed in the United States, two in the East, one in the
Midwest and one in the West.
33
The Company along with other Southwest transmission owners is in the
process of forming an RTO including support for a filing that was made on
October 16, 2001 with the FERC (see Other Issues Facing the Company - Formation
of a Regional Transmission Organization).
Although it is unable to predict the ultimate outcome of these
legislative initiatives, 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.
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 September 30, 2001
Compared to Three Months Ended September 30, 2000
Three Months Ended September 30, 2001
Utility
--------------------------------------------- Generation
Electric Gas and Trading
----------------------- --------------------- ---------------------
Operating revenues:
External customers................... $153,535 99.88% $ 39,649 100.00% $ 428,531 81.79%
Intersegment revenues................ 177 0.12 - 0.00 95,413 18.21
----------- ---------- ---------- --------- ---------- ---------
Total revenues....................... 153,712 100.00 39,649 100.00 523,944 100.00
----------- ---------- ---------- --------- ---------- ---------
Cost of energy sold.................... 1,145 0.74 14,330 36.14 414,490 79.11
Intersegment purchases................. 95,413 62.07 - 0.00 177 0.03
----------- ---------- ---------- --------- ---------- ---------
Total fuel costs..................... 96,558 62.82 14,330 36.14 414,667 79.14
----------- ---------- ---------- --------- ---------- ---------
Gross margin........................... 57,154 37.18 25,319 63.86 109,277 20.86
----------- ---------- ---------- --------- ---------- ---------
Administrative and general costs....... 9,114 5.93 10,475 26.42 8,636 1.65
Energy production costs................ 184 0.12 493 1.24 35,547 6.78
Depreciation and amortization.......... 8,220 5.35 5,400 13.62 10,565 2.02
Transmission and distribution costs.... 10,180 6.62 8,125 20.49 97 0.02
Taxes other than income taxes.......... 2,867 1.87 1,338 3.37 2,367 0.45
Income taxes........................... 8,305 5.40 (1,162) (2.93) 18,842 3.60
----------- ---------- ---------- --------- ---------- ---------
Total non-fuel operating expenses.... 38,870 25.29 24,669 62.22 76,054 14.52
----------- ---------- ---------- --------- ---------- ---------
Operating income....................... $18,284 11.89% $ 650 1.64% $ 33,223 6.34%
----------- ---------- ---------- --------- ---------- ---------
34
Three Months Ended September 30, 2000
Utility
-------------------------------------------- Generation
Electric Gas and Trading
--------------------- ---------------------- --------------------
Operating revenues:
External customers................... $149,970 99.88% $ 55,133 100.00% $ 294,131 76.44%
Intersegment revenues................ 177 0.12 - 0.00 90,638 23.56
---------- --------- ---------- ---------- ----------- --------
Total revenues....................... 150,147 100.00 55,133 100.00 384,769 100.00
---------- --------- ---------- ---------- ----------- --------
Cost of energy sold.................... 1,442 0.96 30,776 55.82 284,301 73.89
Intersegment purchases................. 90,638 60.37 - 0.00 177 0.05
---------- --------- ---------- ---------- ----------- --------
Total fuel costs..................... 92,080 61.33 30,776 55.82 284,478 73.93
---------- --------- ---------- ---------- ----------- --------
Gross margin........................... 58,067 38.67 24,357 44.18 100,291 26.07
---------- --------- ---------- ---------- ----------- --------
Administrative and general costs....... 9,787 6.52 8,279 15.02 9,585 2.49
Energy production costs................ 296 0.20 328 0.59 32,230 8.38
Depreciation and amortization.......... 7,856 5.23 4,990 9.05 10,170 2.64
Transmission and distribution costs.... 8,519 5.67 6,020 10.92 (1) 0.00
Taxes other than income taxes.......... 2,938 1.96 1,614 2.93 2,216 0.58
Income taxes........................... 9,569 6.37 263 0.48 13,771 3.58
---------- --------- ---------- ---------- ----------- --------
Total non-fuel operating expenses.... 38,975 25.96 21,494 38.99 67,970 17.67
---------- --------- ---------- ---------- ----------- --------
Operating income....................... $19,092 12.72% $ 2,863 5.19% $ 32,321 8.40%
---------- --------- ---------- ---------- ----------- --------
UTILITY OPERATIONS
Electric - Operating revenues increased $3.6 million (2.4%) for the
period to $153.7 million primarily due to an increase in transmission wheeling
revenues of $3.1 million as a result of additional capacity sales. Retail
electricity delivery grew 2.4% to 2.02 million MWh in 2001 compared to 1.98
million MWh delivered in the prior year period. This volume increase was the
result of normal load growth.
The gross margin, or operating revenues minus cost of energy sold,
decreased $0.9 million reflecting an increase in intersegment transfer pricing,
partially offset by the increase in transmission wheeling revenues. Gross margin
as a percentage of revenues declined from 38.7% to 37.1%. 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 decreased $0.7 million (7.0%)
primarily due to lower bad debt expense, partially offset by consulting expenses
in connection with cost control and process improvement initiatives. By 2001,
the Company had resolved most of the problems associated with the implementation
of its new billing system (see "Other Issues Facing the Company - Implementation
of New Customer Billing System.") As a result, bad debt expense was
significantly lower in 2001. As a percentage of revenues, administrative and
general costs decreased to 5.9% from 6.5% for the three months ended September
30, 2001 and 2000, respectively as a result of the decrease in costs.
35
Transmission and distribution costs increased $1.7 million (19.5%)
primarily as a result of a non-recurring increase in maintenance to improve
reliability for the transmission and distribution systems. These increased
expenses are not expected to continue into 2002. Transmission and distribution
costs as a percentage of revenues increased from 5.7% to 6.6 % due to the
increase in costs.
Gas - Operating revenues decreased $15.5 million (28.1%) for the period
to $39.6 million. This decrease was driven by a 28.8% decrease in the average
rate charge per decatherm due to lower market prices for natural gas in the
third quarter of 2001 and a 3.8% volume decrease. As a result of a weak
wholesale electricity market in the third quarter, demand for natural gas
decreased significantly. These declines were partially offset by a gas rate
increase which became effective October 30, 2000. Industrial customer volume
decreased 93.8% and revenues decreased $11.1 million. This decline was primarily
attributed to the Company's Generation and Trading Operations due to weak
wholesale market pricing. 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. Residential and commercial customers volume increased 6.8%;
however, due to the lower prices, revenues decreased $3.2 million. These
decreases were partially offset by an increase in transportation volume of 13.0%
and revenues of $2.4 million. The Company does not earn cost of service revenues
on transportation customers.
The gross margin, or operating revenues minus cost of energy sold,
increased $1.0 million (3.9%). This increase is due to the rate increase and
higher off-system transportation volumes partially offset by the decrease in
volumes. The Company purchases natural gas in the open market and resells it at
cost to its distribution customers. As a result, the change in gas prices
driving cost of sales revenues does not have an impact on the Company's gross
margin or earnings.
Administrative and general costs increased $2.2 million (26.5%). This
increase is due to additional customer service expense for increased collection
activities. The significantly higher natural gas prices experienced during the
2000-2001 heating season resulted in higher than normal delinquency rates. In
addition, the Company incurred certain consulting expenses in connection with
its cost control initiatives.
Depreciation and amortization increased $0.4 million (8.2%) for the
period due to additions to the depreciable plant base.
Transmission and distribution costs increased $2.1 million (35.0%) as a
result of a one-time increase in maintenance to improve reliability for the
transportation and distribution systems. These increased expenses are not
expected to continue into 2002.
GENERATION AND TRADING OPERATIONS
Operating revenues grew $139.2 million (36.2%) for the period to $523.9
million. This increase in wholesale electricity sales primarily reflects higher
regional wholesale electric prices. However, prices have been declining since
the end of the second quarter of 2001 (see below). The Company delivered
wholesale (bulk) power of 3.5 million MWh of electricity this period compared to
3.3 million MWh delivered in the prior period, an increase of 6.8%. The MWh
increase is attributable to increased wholesale trading activity during the
period.
36
The strong wholesale electric prices experienced in the second half of
2000 and the first half of 2001 were caused by limited power generation
capacity, increased natural gas prices and the power supply/demand imbalance in
the Western United States. The wholesale electric and natural gas markets
experienced falling price levels at the end of the second quarter of 2001, which
continued through the third quarter of 2001. These price declines were due to
California conservation measures, moderate weather, the economic slowdown and
FERC price caps (see "Western United States Wholesale Power Market"). Since the
end of the second quarter, prices have declined significantly, and liquidity in
the market place - the opportunity to buy/resell power - declined as trading
activity 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 continue to decline in
the fourth quarter 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 $294.1 million to $428.5 million, a 45.7%
increase. The increase was largely price driven.
The gross margin, or operating revenues minus cost of energy sold,
increased $9.0 million (9.0%). Gross margin as a percentage of revenues
decreased from 26.1% to 20.9% reflecting increased prices for purchased power
for resale and increased purchases due to an unscheduled outage at San Juan. A
$4.6 million reduction in the Company's allowances for market price volatility
and credit risk in the wholesale power market, as a result of the falling prices
in the third quarter, contributed to the increase in gross margin (see "Other
Issues Facing The Company - Western United States Wholesale Power Market"). In
addition, the Company recorded unrealized mark-to-market losses of $0.6 million
relating to its power trading contracts in the third quarter of 2001. In 2000,
the Company recognized a $12.1 unrealized gain relating to its power trading
contracts (see Note 4 of the Notes to Consolidated Financial Statements). These
items were recorded as revenue adjustments.
Administrative and general costs decreased $0.9 million (9.9%) for the
period. This decrease is primarily due to business development costs in the
prior year, which did not reoccur in 2001, of $4.5 million related to the
acquisition of a long-term wholesale customer. This decrease is offset by higher
power marketing expenses resulting from increased incentive bonuses and certain
business development related consulting fees. In addition, decreased capital
activity resulted in a smaller portion of overhead costs being allocated to
capital projects. As a percentage of revenues, administrative and general costs
decreased to 1.7% from 2.5% for the three months ended September 30, 2001 and
2000, respectively as a result of increased revenues and decreased costs.
Energy production costs increased $3.3 million (10.3%) for the period.
The increase is primarily due to higher maintenance costs in 2001 resulting from
an unscheduled outage at San Juan Unit 3. As a percentage of revenues, energy
production costs decreased from 8.4% to 6.8%. The decrease is primarily due to
the significant increase in revenues.
37
UNREGULATED BUSINESSES
Due to the cessation of much of Avistar's historic operations, business
activity declined significantly (see "Overview - Avistar"). Revenues decreased
25.9% for the period. Operating losses for Avistar decreased from $1.3 million
in the prior year period to $0.7 million in the current year period primarily
due to decreased business activity.
CONSOLIDATED
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, increased $2.8 million for
the period from $6.9 million to $9.7 million. This increase was due to higher
legal costs, expenses related to business development and an increase in bonus
accruals reflecting the Company's earnings profile for 2001.
Corporate taxes other than income decreased $2.5 million due to higher
tax liabilities in the prior year period as a result of favorable audit outcomes
by certain tax authorities and tax planning strategies.
Other income and deductions, net of taxes, decreased $14.5 million for
the period to income of $1.0 million primarily due to certain gains recognized
in 2000 which did not reoccur in 2001. In 2000, the Company recognized gains of
$13.8 million (pre-tax) related to the settlement of a lawsuit and $4.6 million
(pre-tax) for the reversal of certain reserves associated with the expected
resolution of two gas rate cases. In the third quarter of 2001, the Company
recorded a charge of $4.2 million (pre-tax) to write-off an investment by
Avistar in a technology Company which was impaired. The current period also had
mark-to-market losses of $0.9 million (pre-tax) on the PVNGS decommissioning
trust assets compared to mark-to-market gains of $0.8 million (pre-tax) in the
prior year period (see Note 4 to the Consolidated Financial Statements) and
increased costs of $0.9 million (pre-tax) related to the Company's proposed
acquisition of Western Resources' electric utility operations. Total costs for
the third quarter 2001 related to the Company's proposed acquisition of Western
Resources were $3.4 million (pre-tax). Recently, certain developments have led
the Company to conclude the acquisition cannot be accomplished under the terms
of the present acquisition agreement (see "Other Issues Facing the Company -
Proposed Acquisition of Western Resources Electric Operations" below).
The Company's consolidated income tax expense was $22.3 million in
the three months ended September 30, 2001, a decrease of $7.5 million for the
period. The Company's income tax effective rate for the three months ended
September 30, 2001 was 40.54% compared to 38.84% for the three months ended
September 30, 2000. Included in the Company's 2001 and 2000 taxable income are
certain non-deductible costs related to the Company's acquisition of Western
Resources' electric utility operations. Excluding the impact of these costs, the
Company's effective tax rate declined to 38.76% for 2001 compared to 38.87% for
2000.
The Company's net earnings for the three months ended September 30,
2001 were $32.8 million, a 30.1% decrease. Excluding the Western Resources'
acquisition costs and the related impact on the effective tax rate and the
38
write-off of the Avistar investment ("2001 Special Items"), the Company's net
earnings were $38.4 million. Net earnings for the three months ended September
30, 2000 were $46.9 million. Excluding the gains for the lawsuit settlement and
the reversal of certain gas rate case reserves, the charge in connection with
the acquisition of a long-term wholesale customer and the Western Resources'
acquisition costs and the related impact on the effective tax rate ("2000
Special Items"), the Company's net earnings were $40.0 million.
Earnings per share on a diluted basis were $0.96 (excluding the 2001
Special Items) for the three months ended September 30, 2001 compared to $1.01
(excluding the 2000 Special Items) for the three months ended September 30,
2000. Diluted weighted average shares outstanding were remained constant at 39.7
million in 2001 and 2000. Net earnings per share from continuing operations
primarily decreased due to a decline in utility operating income.
Nine Months Ended September 30, 2001 Compared to
Nine Months Ended September 30, 2000
The table below sets forth the operating results as percentages of total
operating revenues for each business segment.
Nine Months Ended September 30, 2001
Utility
------------------------------------------- Generation
Electric Gas and Trading
----------------------- ------------------- ----------------------
Operating revenues:
External customers................... $424,249 99.88% $318,670 100.00% $1,280,141 83.13%
Intersegment revenues................ 530 0.12 - 0.00 259,726 16.87
----------- ---------- --------- --------- ----------- ---------
Total revenues....................... 424,779 100.00 318,670 100.00 1,539,867 100.00
----------- ---------- --------- --------- ----------- ---------
Cost of energy sold.................... 3,957 0.93 220,547 69.21 1,136,400 73.80
Intersegment purchases................. 259,726 61.14 - 0.00 530 0.03
----------- ---------- --------- --------- ----------- ---------
Total fuel costs..................... 263,683 62.08 220,547 69.21 1,136,930 73.83
----------- ---------- --------- --------- ----------- ---------
Gross margin........................... 161,096 37.92 98,123 30.79 402,937 26.17
----------- ---------- --------- --------- ----------- ---------
Administrative and general costs....... 29,660 6.98 34,162 10.72 20,296 1.32
Energy production costs................ 687 0.16 1,306 0.41 107,135 6.96
Depreciation and amortization.......... 24,311 5.72 16,023 5.03 31,981 2.08
Transmission and distribution costs.... 26,621 6.27 21,829 6.85 310 0.02
Taxes other than income taxes.......... 8,527 2.01 4,989 1.57 6,611 0.43
Income taxes........................... 22,616 5.32 4,532 1.42 84,698 5.50
----------- ---------- --------- --------- ----------- ---------
Total non-fuel operating expenses.... 112,422 26.47 82,841 26.00 251,031 16.30
----------- ---------- --------- --------- ----------- ---------
Operating income....................... $48,674 11.46% $15,282 4.80% $ 151,906 9.86%
----------- ---------- --------- --------- ----------- ---------
39
Nine Months Ended September 30, 2000
Utility
-------------------------------------------- Generation
Electric Gas and Trading
--------------------- ---------------------- --------------------
Operating revenues:
External customers..................... $406,034 99.87% $ 204,193 100.00% $537,647 68.67%
Intersegment revenues.................. 530 0.13 - 0.00 245,330 31.33
---------- --------- ---------- ---------- ---------- ---------
Total revenues......................... 406,564 100.00 204,193 100.00 782,977 100.00
---------- --------- ---------- ---------- ---------- ---------
Cost of energy sold...................... 3,707 0.91 118,706 58.13 542,223 69.25
Intersegment purchases................... 245,330 60.34 - 0.00 530 0.07
---------- --------- ---------- ---------- ---------- ---------
Total fuel costs....................... 249,037 61.25 118,706 58.13 542,753 69.32
---------- --------- ---------- ---------- ---------- ---------
Gross margin............................. 157,527 38.75 85,487 41.87 240,224 30.68
---------- --------- ---------- ---------- ---------- ---------
Administrative and general costs......... 27,299 6.71 27,585 13.51 18,279 2.33
Energy production costs.................. 924 0.23 1,117 0.55 102,361 13.07
Depreciation and amortization............ 23,903 5.88 14,870 7.28 30,873 3.94
Transmission and distribution costs...... 24,385 6.00 20,198 9.89 23 0.00
Taxes other than income taxes............ 9,433 2.32 5,422 2.66 7,550 0.96
Income taxes............................. 22,854 5.62 3,353 1.64 18,529 2.37
---------- --------- ---------- ---------- ---------- ---------
Total non-fuel operating expenses...... 108,798 26.76 72,545 35.53 177,614 22.68
---------- --------- ---------- ---------- ---------- ---------
Operating income......................... $48,729 11.99% $ 12,942 6.34% $ 62,610 8.00%
---------- --------- ---------- ---------- ---------- ---------
UTILITY OPERATIONS
Electric - Operating revenues increased $18.2 million (4.5%) for the
period to $424.8 million. Retail electricity delivery grew 3.0% to 5.52 million
MWh in 2001 compared to 5.36 million MWh delivered in the prior year period,
resulting in increased revenues of $8.3 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 $8.1 million
as a result of additional capacity sales not likely to recur in 2002 and other
revenues increased $1.8 million primarily for new property leasing for
telecommunication systems.
The gross margin, or operating revenues minus cost of energy sold,
increased $3.6 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 37.9%. 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 (8.6%) 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 and consulting expenses in connection with cost control and process
improvement initiatives. These increases were partially offset by lower bad debt
40
expense. By December 2000, the Company had resolved most of the problems
associated with the implementation of its new billing system (see "Other Issues
Facing the Company - Implementation of New Customer Billing System"). As a
result bad debt expense was significantly lower in 2001. As a percentage of
revenues, administrative and general costs increased to 7.0% from 6.7% for the
nine months ended September 30, 2001 and 2000, respectively, primarily as a
result of the increased pension and benefits costs.
Transmission and distribution costs increased $2.2 million (9.2%)
primarily due to a non-recurring increase in maintenance to improve reliability
for the transmission and distribution systems. These expenses are not expected
to continue in 2002. Transmission and distribution costs as a percentage of
revenues increased to 6.3% from 6.0% for the nine months ended September 30,
2001 and 2000, respectively due to the increased costs.
Taxes other than income decreased $0.9 million (9.6%) due to higher tax
liabilities in the prior year period as a result of favorable audit outcomes by
certain tax authorities and tax planning strategies. Taxes other than income as
a percentage of revenues decreased to 2.0% from 2.3%.
Gas - Operating revenues increased $114.5 million (56.1%) for the
period to $318.7 million. This increase was driven by a 42.7% increase in the
average rate charge per decatherm due to high wholesale gas prices in 2001
resulting from increased market demand, a 10.3% volume increase and a gas rate
increase, which became effective October 30, 2000. Residential and commercial
customers volume increased 9.9% due to a colder winter during 2001. Customer
volume, other than residential and commercial, increased 10.4%. 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 in the Western United States during 2001. This increase
is not expected to recur in 2002. 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 $12.6 million (14.8%). 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, which will likely not recur in
2002. 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 $6.6 million (23.8%). This
increase is due to increased pension and benefits expense resulting primarily
from lower than expected investment returns on related plan assets, consulting
expenses in connection with cost control and process improvement initiatives and
increased bad debt and collection costs. The significantly higher natural gas
prices experienced during the 2000-2001 heating season resulted in higher than
normal delinquency rates. This trend is similar to historic collection trends
and patterns associated with past natural gas price spikes.
Depreciation and amortization increased $1.2 million (7.8%) for the
period due to a higher depreciable plant base.
41
Transmission and distribution costs increased $1.6 million (8.1%)
primarily due to increased maintenance to improve reliability for the
transmission and distribution systems. These increased expenses are not expected
to continue in 2002.
GENERATION AND TRADING OPERATIONS
Operating revenues grew $756.9 million (96.7%) for the period to $1.5
billion. This increase in wholesale electricity sales primarily reflects
continued strong regional wholesale electric prices. However, prices have been
declining since the end of the second quarter of 2001 (see below). The Company
delivered wholesale (bulk) power of 9.8 million MWh of electricity this period,
compared to 9.6 million MWh in 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 will recur in 2002. At the end of the second quarter of
2001, the market experienced falling price levels. This trend continued in the
third quarter of 2001. 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 the fourth quarter of 2001 (see - "Future
Expectations"). The Company also believes that current weak market pricing is
not sustainable and that prices will adjust to more normal historical levels in
2002.
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 risk management and credit
policies, limits the Company's wholesale sales in a volatile market. Wholesale
revenues from third-party customers increased from $537.6 million to $1.3
billion, a 138.1% increase. The increase was largely price driven.
The gross margin, or operating revenues minus cost of energy sold,
increased $162.7 million (67.7%). Gross margin as a percentage of revenues
decreased from 30.7% to 26.2% reflecting increased prices for purchased power
for resale. Higher margins were partially offset by unrealized mark-to-market
losses of $24.9 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 2000, the Company
recognized a $1.7 million unrealized loss resulting to its power trading
contracts (see Note 4 of the Notes to Consolidated Financial Statements). In
addition, the Company recorded $2.1 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 $2.0 million (11.0%) for the
period. This increase is primarily due to increased pension and benefits
expense, higher power marketing expenses mainly for additional incentive bonuses
and certain consulting fees and other expenses related to business development
and process improvement. In the prior year, Generation and Trading recognized
42
business development costs of $4.5 million related to the acquisition of a
long-term wholesale customer. As a percentage of revenues, administrative and
general costs decreased to 1.3% from 2.3% for the nine months ended September
30, 2001 and 2000, respectively as a result of increased wholesale revenues.
Energy production costs increased $4.8 million (4.7%) for the year. The
increase is primarily due to higher maintenance costs in 2001 resulting from
scheduled and unscheduled outages at San Juan Unit 3, additional incentive
bonuses at San Juan, 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. This increase was partially offset by lower maintenance
costs at Four Corners as a result of decreased outage time. As a percentage of
revenues, energy production costs decreased from 13.1% to 7.0%. The decrease is
primarily due to the significant increase in wholesale revenues.
Depreciation and amortization increased $1.1 million (3.6%) for the
period due to a higher depreciable plant base. Depreciation and amortization as
a percentage of revenues decreased from 3.9% to 2.1% due to the increase in
wholesale revenues.
Taxes other than income decreased $0.9 million (12.4%) due to higher
tax liabilities in the prior year period as a result of favorable audit outcomes
by certain tax authorities and tax planning strategies. Taxes other than income
as a percentage of revenues decreased from 1.0% to 0.4% as a result of the
increase in wholesale revenues.
UNREGULATED BUSINESSES
Due to the cessation of much of Avistar's historic operations, business
activity declined significantly (see "Overview - Avistar"). Revenues decreased
24.8% for the period. Operating losses for Avistar increased from $3.3 million
in the prior year period to $3.5 million in the current year period primarily
due to increased costs related to the shutdown of certain operations.
CONSOLIDATED
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, increased $4.0 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").
Other income and deductions, net of taxes, decreased $40.7 million for
the period to a loss of $10.9 million primarily due to certain gains recognized
in 2000, which did not reoccur in 2001 and certain write-off's in 2001. In 2000,
the Company recognized gains of $13.8 million (pre-tax) related to the
settlement of a lawsuit, $4.5 million (pre-tax) for the reversal of certain
reserves associated with the expected resolution of two gas rate cases and $2.4
million (pre-tax) related to the Company's hedge of certain non-qualified
retirement plan trust assets. In the current year, the Company recorded charges
of $13.1 million (pre-tax) to write-off certain Avistar investments, which were
43
permanently impaired (see "Overview - Avistar"). In addition in 2001, the
Company recognized 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 results also
include 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 of $2.7 million (pre-tax) on the PVNGS
decommissioning trust assets compared to mark-to-market gains of $2.6 million
(pre-tax) in the prior year (see Note 4 to the Consolidated Financial
Statements) and increased costs of $5.5 million (pre-tax) related to the
Company's proposed acquisition of Western Resources' electric utility
operations. Total costs for the nine months ended September 30, 2001 related to
the Company's proposed acquisition of Western Resources were $8.0 million
(pre-tax). Recently, certain developments have led the Company to conclude the
acquisition cannot be accomplished under the terms of the present acquisition
agreement (see "Other Issues Facing the Company - Proposed Acquisition of
Western Resources Electric Operations" below). The Company has expensed all
costs related to the acquisition to date.
The Company's consolidated income tax expense was $85.9 million in the
nine months ended September 30, 2001, an increase of $33.7 million for the
period. The Company's income tax effective rate for the nine months ended
September 30, 2001 was 37.06%. Included in the Company's 2001 taxable income are
certain non-deductible costs related to the Company's proposed 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 for 2001
was 38.88%. The Company's effective tax rate for the nine months ended September
30, 2000 was 37.53%. The Company's 2000 taxable income also includes certain
non-deductible costs related to the Company's proposed acquisition of Western
Resources' electric utility operations. Excluding the impact of these costs, the
Company's effective tax rate for 2000 was 37.57%. The increase in the effective
rate was primarily due to an increase in the depreciation of flow through items.
The Company's net earnings for the nine months ended September 30,
2001 were $145.9 million, a 68.0% increase. Excluding the write-off of coal mine
decommissioning costs, the donation to the PNM Foundation, the charges related
to Avistar and the Western Resources' acquisition costs and the related impact
on the effective tax rate ("2001 Special Items"), the Company's net earnings in
44
2001 were $171.9 million. Net earnings for the nine months ended September 30,
2000 were $86.9 million. Excluding the gains for the lawsuit settlement, the
reversal of certain gas rate case reserves, the charge in connection to the
acquisition of a long-term wholesale customer, the charges related to the
Western Resources' acquisition costs and the related impact on the effective tax
rate ("2000 Special Items"), the Company's net earnings in 2000 were $80.0
million.
Earnings per share on a diluted basis were $4.31 (excluding the 2001
Special Items) for the nine months ended September 30, 2001 compared to $2.00
(excluding the 2000 Special Items) for the nine months ended September 30, 2000.
Diluted weighted average shares outstanding were 39.8 million in 2001 and 39.7
million 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 October 24, 2001, the Company announced that it expects full year
2001 earnings to be at least $4.50 per share. While forecasting a substantial
increase in earnings for 2001, management does not believe those gains will
recur in 2002 and beyond. 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. Wholesale electricity prices have decreased 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 forward to 2002, management believes that its sustainable earnings
per share are in a range of $3.00 to $3.50. This expectation is based on
management's view of the Western United States wholesale power market and the
Company's power market positioning and base earnings ability. It also assumes
the FERC price caps will not be decreased further and will be lifted as
scheduled. The high end of the 2002 sustainable earnings range assumes 2002
Western United States wholesale power market prices will be in the range of $45
per MWh. This assumed price is above forward prices for 2002 as of October 24,
2001. The impact of wholesale electricity price movement on expected earnings
per share amount is difficult to project. The calculation is subject to numerous
variables, including but not limited to, on and off-peak wholesale demand,
retail load needs, natural gas prices, the current position of the Company's
trading portfolio and general economic conditions. If average wholesale prices
were to decrease to $30 per MWh (the current forward price), management believes
sustainable earnings to be around $3.00 per share.
As the Company adds new generation resources, it is expected that
earnings will trend upwards as sales volumes grow. This growth is expected to be
in high single digits, 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.
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
45
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 September 30, 2001, the Company had working capital of $182.4
million including cash and cash equivalents of $222.6 million. This is an
increase in working capital of $34.6 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 nine months ended
September 30, 2001 was $296.9 million, an increase of $126.6 million from 2000.
This increase was primarily the result of increased profitability. Contributing
to this increase was the timing of payments for purchased power, the recovery of
purchased gas adjustments from utility customers and a decrease in utility
customer accounts receivable primarily as a result of seasonal volume declines.
Also, the increase in wholesale accounts receivable was lower than the prior
year increase. In addition, the Company did not make the first quarter 2001
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 payment is due January 2002. Improved operating cash
flows have driven the Company's cash balance up to $286.1 million from $107.7
million at December 31, 2000.
Cash used for investing activities was $153.9 million in 2001 compared
to $86.7 million in 2000. This increased spending reflects combustion turbine
progress payments of $68.0 million in 2001 compared to $21.4 million in 2000 and
$7.5 million related to the acquisition of certain transmission assets.
Cash used for financing activities was $28.1 million compared to $85.5
million in 2000. Cash used for financing activities in 2001 was primarily for
dividend requirements. The decrease in cash used for financing activities from
2000 to 2001 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 wholesale
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 has committed to purchase five combustion turbines totaling
$151.3 million. The turbines are for three planned power generation plants with
46
a combined capacity of 657 MWs. The plants estimated cost of construction is
approximately $400.3 million. The Company has expended $89.4 million as of
September 30, 2001. In November, 2001, the Company plans to break ground for a
new 135 MW single cycle gas turbine plant on a site in Southern New Mexico.
Currently the Company plans to expand the facility to 540 MW by 2003. Contracts
have not been finalized on the remaining planned construction. 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.
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
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 November 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 November 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 and wholesale 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. On October 19, 2001, S&P removed the
Company from negative credit watch. 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 PVNGS 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
47
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 2005. 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 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
on December 1, 2001, as permitted under the amended Restructuring Act, without
corporate separation of supply service and energy-related services assets from
distribution and transmission services assets. 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. The transfer of the
subsidiaries and certain assets to the holding company is subject to receipt of
an additional order from the PRC, which may not be received until after
formation of the holding company through the mandatory share exchange. 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 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 basis
and imposes certain regulatory requirements regarding merchant generation
plants. The Company believes that certain conditions imposed by the PRC order
are unlawful 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 did not act on the Company's request,
and the request was deemed denied on August 16, 2001. Despite this adverse
48
ruling, the Company plans to proceed with its plans to activate PNM Resources
and complete the mandatory share exchange. At the same time, the Company will
continue with its efforts to minimize the adverse effects of the order. On
September 14, 2001, the Company asked the New Mexico Supreme Court to review the
holding company order. The Company believes the PRC exceeded its jurisdiction
and placed certain conditions on the new corporate structure that the Company
believes are unlawful. The Attorney General has filed a cross-appeal. The
Company is unable to predict the outcome of its appeal or the cross-appeal. In
filings with the PRC, Staff and other parties have raised the issue whether the
Company can form the holding company pending appeal. The Company has filed its
response and intends to vigorously defend its right to form the holding company
pending appeal. The Company is unable to predict what action the PRC may take
regarding this issue (see "Overview - Restructuring the Electric Utility
Industry").
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, the
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 nine months ended September 30, 2001.
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
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 September 30, 2001 and December 31, 2000 is shown below:
September 30, December 31,
2001 2000
--------------- --------------
Common Equity...................... 51.5 % 48.6 %
Preferred Stock.................... 0.7 0.7
Long-term Debt..................... 47.8 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 September 30, 2001 and $166 million
as of December 31, 2000. Including such obligations the Company's
long-term debt percentage would increase to 51.8% for 2001 and
54.7% for 2000.
49
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
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 provide the opportunity for
amortization of coal mine decommissioning costs currently estimated at
approximately $100 million. The Company intends to seek recovery of these costs
in its next rate case filing and believes that such costs are fully recoverable.
The Company believes that any remaining portion of the regulatory assets will be
fully recovered in 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
50
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 from 2007 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.
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.
51
MERCHANT PLANT FILING
Senate Bill 266, enacted by the 2001 session of the New Mexico
legislature, allowed public utilities to "invest in, construct, acquire or
operate" a generating plant not intended to provide retail electric service,
free of certain otherwise applicable limitations of the Public Utility Act. By
order entered on March 27, 2001, the PRC found that these provisions of SB 266
raised issues such as cost allocations for ratemaking, revenue allocations for
off-system sales, how the Commission can ensure the utility will meet its duty
to provide service when the utility invests in such generating plant, how that
plant will be financed and how transactions between regulated plant and such
generating plant will be conducted. The PRC's March 27 order directed the
Company to file a pleading addressing these issues by July 25, 2001. The Company
filed such a pleading, to which the Commission's utility staff and intervenors
filed responses. On October 2, 2001, the Commission entered another order,
specifically directing the Company to file written testimony "providing detailed
support for its positions and plans on each topic identified by the Commission's
March 27 Order" and by responses filed by certain parties. The required
testimony was to be filed by November 6, 2001. The Company subsequently
requested and was granted an extension to December 10, 2001 in which to file the
required testimony. The Company is unable to predict the impact these
proceedings may have on its plans to expand its generating capacity (see
"Overview - Competitive Strategy").
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
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 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 split off to Western Resources' shareholders prior to
the acquisition of Western's electric utility assets by the Company.
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.
52
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 Industries stock in connection
with the split-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 a limited incentive to reduce Western Resources net debt balance prior to
the consummation of the transaction by selling non-utility assets or through
certain other debt reduction acitivities. 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 $641 million of additional equity infusions and existing
intercompany receivables 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 Industries 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 Industries.
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.
At closing, Jeffry 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
53
Board of Directors of the new company will consist of six current Company board
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 present if available, that 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 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 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 would be 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 Industries is a condition of the proposed
acquisition of Western Resources' electric utility assets.
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 Resources to file a financial plan
within 90 days to restore Western Resources' financial ratings to the investment
grade level of similarly situated electric public utilities. Western Resources
filed for reconsideration of the order. On October 3, 2001, the KCC issued its
order on reconsideration of the split-off order, reaffirming its prior order
prohibiting the split-off as presently designed and confirming that a merger
would not cure the problems associated with the split-off. In October 2001,
Western Resources filed petitions for judicial review in the District Court of
Shawnee County, Kansas, of the split-off order and the reconsideration order.
On July 25, 2001, the KCC issued an order reducing the rates of Western
Resources' electric utilities by the net amount of $22.7 million annually.
Western Resources had sought a combined increase of approximately $151 million
annually. Western Resources filed for reconsideration of the order and on
September 5, 2001, the KCC slightly increased rates resulting in a revised net
54
reduction of approximately $15.7 million annually. Western Resources and other
parties in the case filed for reconsideration of the KCC's revised rate order.
On October 11, 2001, the KCC issued an order denying all petitions for
reconsideration of the revised rate order.
On July 30, 2001, the Company and Western Resources issued a joint
release stating that the transaction as presently designed would be difficult to
complete if the KCC orders remain in effect. The release announced that the
Company and Western Resources would begin discussions on how to modify the
transaction to make it possible to obtain necessary regulatory approvals.
On August 13, 2001, the Company announced that Western Resources had
decided to discontinue the talks about modifying the transaction and desired to
attempt to pursue completion 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 Resources has advised
the Company that it does not believe that the rate case order results in a
material adverse effect.
Western Resources has requested that the Company file for regulatory
approvals of the transaction as presently designed, despite the fact that the
transaction requires the split-off already determined to be unlawful by the KCC.
As a result of the disagreement over the viability of the transaction as
presently designed, the Company filed suit on October 12, 2001, in New York
state court seeking declarations that the transaction could not be accomplished
as presently designed due to the KCC's determination that the split-off
condition of the transaction is unlawful; that the Company is not obligated to
pursue approvals of the transaction as presently designed; that the transaction
is terminated effective December 31, 2001, without an automatic extension; and
that the KCC rate case order constitutes a material adverse effect under the
agreement. The Company also seeks monetary damages for breach of contract
because Western Resources represented and warranted that the split-off did not
require approval of the KCC. Western Resources' response to the Complaint is due
on November 26, 2001. The Company is unable to predict the outcome of this
proceeding.
On November 6, 2001, Western Resources filed its financial plan for
restructuring its debt pursuant to the KCC's July 20 order. The plan is
essentially comprised of two parts. The first part is stated by Western
Resources as being designed to reduce debt by $100 to $175 million in the next
several months by means of a rights offering of between 8.7 million and 19.1
million Westar Industries shares to Western Resources shareholders, representing
between 10.2% and 19.9% of outstanding shares of Westar Industries. The second
part is stated by Western Resources as being designed to reduce debt below $1.8
billion over the next one to three years through the sale by Western Resources
of its Westar Industries common stock or Western Resources shares. The second
part would not take place unless Westar Industries' stock price trades for 45
consecutive trading days at a price 25% higher than the price necessary to
reduce Western Resources' debt below $1.8 billion. The first part of the plan is
acknowledged by Western to be similar to the split-off ruled unlawful by the KCC
but Western Resources asserts that it has made certain modifications in an
attempt to address concerns raised by the KCC. The Company continues to monitor
proceedings in Kansas but intends to pursue the litigation filed in New York.
55
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
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 became extremely volatile and, while
providing many marketing opportunities, continues to present significant risk to
companies selling power into this marketplace.
Recently moderate weather in California as well as certain regulatory
actions (see below) have caused a significant decline in the price of wholesale
electricity in the Western United States wholesale power market. In addition,
the Company expects conservation measures and new generation to put downward
pressure on wholesale electricity prices. As a result of these trends, the
Company expects its earnings from wholesale power trading operations to be
significantly lower in the future (see "Results of Operations - Future
Expectations").
The power market in the Western United States has been the subject of
widespread national attention. At the heart of the situation were flaws in the
California deregulation legislation and a significant imbalance between electric
supply and demand. These circumstances were aggravated by other factors such as
increases in gas supply costs, weather conditions and transmission constraints.
The FERC and the California Public Utilities Commission ("CPUC") have 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.
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
56
previously established and applied 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 third quarter
and remained low subsequent to the end of the third 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 Pacific
Northwest matter was heard by an administrative law judge whose recommended
decision declined to order refunds resulting from sales into the Pacific
Northwest, but the FERC has not yet acted on this recommended decision. The
hearing on potential California refund obligations has not yet been completed.
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 proofs of claims in the Cal PX and PG&E 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
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 were financed by legislative appropriation, with the expectation that
57
this funding would be replaced with the issuance of revenue bonds by the state
under recent legislation signed by the California governor. In the first quarter
of 2001, the Company began to sell power to the Cal DWR. The Company has
regularly monitored 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 $2.1 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 September 30, 2001, the
Company believes the total allowance for anticipated losses, currently
established at $10.6 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.
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
58
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 nine months ended September 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 September 30, 2001, the Company believes the allowance
for doubtful accounts of $8.3 million is adequate for management's estimate of
potential uncollectible accounts.
The following is a summary of the allowance for doubtful accounts
during the nine months ended September 30, 2001 and the year ended December 31,
2000:
September 30, December 31,
2001 2000
------------- ------------
Allowance for doubtful accounts, beginning
of year................................................... $ 8,963 $12,504
Bad debt expense............................................ 3,373 9,980
Less: Write off (adjustments) of uncollectible accounts.... 4,019 13,521
------------- -------------
Allowance for doubtful accounts, end of period.............. $ 8,317 $ 8,963
============= =============
59
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 parties have filed final briefs with the FERC and are engaged in
settlement discussions before a settlement judge under FERC procedures. 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. A related PRC proceeding has been stayed,
pending the outcome of the FERC 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
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.
60
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 has been approved by the USBR and also has received all requisite
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.
FERC MANDATED REGIONAL TRANSMISSION ORGANIZATIONS
Beginning with the passage of the Public Utilities Regulatory Policy
Act of 1978 and, subsequently, the Energy Policy Act, there has been a
significant increase in the level of competition in the market for the
generation and sale of electricity. The Energy Policy Act reduced barriers to
market entry for companies wishing to build, own and operate electric generating
facilities, and it also promoted competition by authorizing the FERC to require
transmission service for wholesale power transactions. In this regard, in 1996,
the FERC issued Order 888. Among other things, Order 888 required electric
utilities controlling transmission facilities to file open access transmission
tariffs that would make the utility transmission systems available to wholesale
sellers and buyers of electric energy on a non-discriminatory basis.
Order 888 encouraged utilities to investigate the formation of
independent system operators, or ISOs, to operate transmission assets and
provided criteria under which the formation, operation and governance of ISOs
would be reviewed. On December 20, 1999, the FERC issued its Order 2000 on
Regional Transmission Organizations, or RTOs. In this order, the FERC
established timelines for transmission owning entities to join an RTO and
defined the minimum characteristics and functions that an RTO must satisfy.
61
In January 1998, the Company entered into a development agreement with
other transmission service providers and users to form an ISO in the southwest.
As a result, Desert STAR, Inc. was incorporated as a non-profit organization in
the State of Arizona on September 21, 1999.
The Desert STAR Board of Directors and the FERC jurisdictional
transmission owners (the"TO's") made various progress filings throughout 2000
and 2001 and held numerous stakeholder, advisory and Desert STAR Board of
Director meetings to work through operational and technical documents to satisfy
the FERC functions and characteristics for an approved RTO. The functions of
Desert STAR RTO were envisioned to include the following: (1) tariff
administration and design; (2) congestion management; (3) parallel flow
internalization; (4) ancillary services; (5) total transmission capability and
available transmission capability estimation; (6) market monitoring; (7)
planning and expansion; and (8) inter-regional coordination.
In an Order issued in March 2001, FERC granted provisional RTO status
to a for-profit RTO with a Delaware LLC registry. The for-profit model's
acceptance by FERC was of interest to the Desert STAR TO's because a for-profit
company was viewed as having the proper motivation to efficiently facilitate
competitive markets and was a stated ultimate goal of Desert STAR. As a result,
the TO's informed the Desert STAR Board of Directors and stakeholders that they
planned to investigate the feasibility of modifying the structure of Desert STAR
to become a for-profit company.
In July 2001, FERC issued a series of Orders requiring existing
independent system operators and developing RTOs in the Eastern United States to
enter into mediation to form a single RTO in the Northeast and a second in the
Southeast. FERC expressed the desire that four RTO's be formed in the United
States, two in the East, one in the Midwest and one in the West.
On August 10, 2001 the Desert STAR Board approved the formation of
WestConnect RTO LLC ("WestConnect"), a for-profit successor to DesertSTAR. On
October 16, 2001 WestConnect filed its complete RTO package with FERC,
requesting a Declaratory Order seeking confirmation from the FERC that the
WestConnect filing satisfies FERC's Order 2000 requirements.
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
companies sued by the Justice Department. Discovery continues in the pending
62
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 not yet known 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 continues 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
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.
63
For the nine months ended September 30, 2001, the Company spent $1.2
million for remediation and $0.7 million for control and prevention. The
majority of the September 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. The Company also is
cooperating with an investigation of the incident by the New Mexico Public
Regulation Commission's Pipeline Safety Bureau. 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.
64
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 dependent 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 was June 30, 2001. A revision was made on October 10, 2001.
The effective date of the revision to the implementation guidance for the
Company is January 1, 2002. The Company is currently in the process of
determining the impact of this guidance.
65
Statement of Financial Accounting Standards No. 143, Accounting for
Asset Retirement Obligations ("SFAS 143"). In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS 143. The statement requires the
recognition of a liability for legal obligations associated with the retirement
of a tangible long-lived asset that result from the acquisition, construction or
development and/or the normal operation of a long-lived asset. The asset
retirement obligation is required to be recognized at its fair value when
incurred. The cost of the asset retirement obligation is required to be
capitalized by increasing the carrying amount of the related long-lived asset by
the same amount as the liability. This cost must be expensed using a systematic
and rational method over the related asset's useful life. SFAS 143 is effective
for the Company beginning January 1, 2003. The Company is currently assessing
the impact of SFAS 143 and is unable to predict its impact on the Company's
operating results and financial position at this time.
Statement of Financial Accounting Standards No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets ("SFAS 144"). In August 2001, the
FASB issued SFAS 144. The statement retains the requirements of the previously
issued pronouncement on asset impairment, Statement of Financial Accounting
Standards No. 121 ("SFAS 121"); however the SFAS 144 removes goodwill from the
scope of SFAS 121, provides for a probability-weighted cash flow estimation
approach for estimating possible future cash flows, and establishes a "primary
asset" approach for a group of assets and liabilities that represents the unit
of accounting to be evaluated for impairment. In addition, SFAS 144 changes the
measurement of long-lived assets to be disposed of by sale, as accounted for by
Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued
operations are no longer measured on a net realizable value basis, and their
future operating losses are no longer recognized before they occur. The Company
does not believe SFAS 144 will have a material effect on its future operating
results or financial position.
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
Company's proposed acquisition of Western Resources and the businesses of the
Company and Western Resources and the uncertainties associated with completing
the transaction. 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 the local and
national economy, changes in supply and demand in the market for electric power,
uncertainties relating to the Company's transaction with Western Resources and
related costs, the performance of generating units and transmission system, and
state and federal regulatory and legislative decisions and actions, including
the wholesale electric power pricing mitigation plan ordered by FERC on June 18,
2001, 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 FERC and the PRC and
66
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: litigation concerning or affecting the transaction,
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 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
September 30, 2001 from its electric trading contracts was $10.8 million.
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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.
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, but may consider such financial instruments in
the future depending on market conditions and the Company's financing
requirements.
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
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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
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.
On October 30, 2001, the DC Circuit issued its opinion granting the
Company's appeal. The Court remanded the proceeding to the EPA for a new
rulemaking on EPA's authority to issue federal operating permits in areas in
which status as Indian Country may be in dispute. The United States has until
December 14, 2001, to file a petition for rehearing in the appeal. 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
complaint (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
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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 the plaintiff's motion to remand the case
back to Kansas State Court. A motion to reconsider has been denied. This case
has been 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
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is and will continue to be a retail customer until the date that 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
requesting the FERC, on an expedited basis, to order the Company to provide
network transmission service to WAPA on behalf of DOE and several other entities
located on KAFB under the Company's Open Access Transmission Tariff. 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. The parties have filed final
briefs with the FERC and are engaged in settlement discussions before a
settlement judge under FERC procedures. 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 PRC case has been stayed, pending the outcome of the FERC
proceeding.
AVISTAR SEVERANCE
When the Company sold its water utility assets to the City of Santa Fe
("City") in 1995, the parties also entered into a Maintenance and Operations
Agreement ("Agreement"), agreeing that the City would offer employment to the
water utility employees when the Agreement expired. The Agreement was assigned
to Avistar, Inc., and it expired July, 2001. The City assumed all maintenance
and operations, and offered employment to the employees.
Because the employees would continue performing the same jobs at the
same location(s), the Company had previously excluded the non-union employees
from eligibility for severance benefits under the Company's non-union severance
plans. Similarly, the IBEW Local 611 had been on notice that the Company had
negotiated for the continued employment of the IBEW-represented employees,
making them ineligible for severance benefits under Article 24 of the Collective
Bargaining Agreement ("CBA") between the Company and the IBEW.
In July 2001, the Agreement ended, and most of the water operations
employees accepted employment with the City. However, on March 27, 2001, the
IBEW began an internal Grievance claiming that about twenty-eight represented
employees now employed by the City are nonetheless eligible for severance
benefits under Article 24 of the CBA. The Company has denied their eligibility.
The Company is evaluating its options, and the parties are pursuing informal
settlement discussions pending the selection of an arbitrator. The Company is
unable to predict the outcome of this matter.
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WESTERN RESOURCES
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
Company believes that the transaction cannot be accomplished under the terms of
the present acquisition agreement if the orders remain in effect (see "Item 2. -
Management's Discussion and Analysis and Results of Operations - Other Issues
Facing The Company - Acquisition of Western Resources Electric Operations.")
Western Resources has demanded that the Company file for regulatory
approvals of the transaction as presently designed, despite the fact that the
transaction requires the split-off already determined to be unlawful by the KCC.
As a result of the disagreement over the viability of the transaction as
presently designed, the Company filed suit on October 12, 2001, in New York
state court seeking declarations that the transaction could not be accomplished
as presently designed due to the KCC's determination that the split-off
condition of the transaction is unlawful; that the Company is not obligated to
pursue approvals of the transaction as presently designed; that the transaction
is terminated effective December 31, 2001, without an automatic extension; and
that the KCC rate case order constitutes a material adverse effect under the
agreement. The Company also seeks monetary damages for breach of contract
because Western Resources represented and warranted that the split-off did not
require approval of the KCC. Western Resources' response to the Complaint is due
on November 26, 2001. The Company is unable to predict the outcome of this
proceeding.
REEVES GENERATING STATION ENVIRONMENTAL MATTERS
On August 15, 2001, the City of Albuquerque Air Quality Division of the
Environmental Health Department ("City"), issued a Notice of Violation ("NOV")
to the Company, alleging that in the period of March 10, 1998 through June 30,
2001, the Company had exceeded the pound-per-inch NOx limitations in the
operating permit for the Reeves Generating Station. The Company was assessed a
proposed penalty in the amount of $1.8 million. The Company disagreed with the
alleged violations and entered into discussions with the City to attempt to
achieve a resolution of the matter. The parties are presently in the process of
negotiating a settlement agreement that would resolve the matter without the
admission of liability by the Company.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
10.5 Water Supply Agreement between the Jicarilla Apache Tribe
and Public Service Company of New Mexico, dated July 17,
2000.
10.9.8 Amendment 11 to the Coal Sales Agreement, dated August 31,
2001 among San Juan Coal Company, the Company and Tucson
Electric Power Company. (Confidential treatment was
requested to portions of this exhibit, and such portions
were omitted from this exhibits filed and were filed
separately with the Securities and Exchange Commission.)
10.83 Transportation Agreement Buy Out Agreement, dated August
31, 2001 among San Juan Transportation Company, the
Company and Tucson Electric Power Company. (Confidential
treatment was requested to portions of this exhibit, and
such portions were omitted from this exhibits filed and
were filed separately with the Securities and Exchange
Commission.)
10.84 Coal Sales Agreement Buy Out Agreement, dated August 31,
2001 among San Juan Coal Company, the Company and Tucson
Electric Power Company. (Confidential treatment was
requested to portions of this exhibit, and such portions
were omitted from this exhibits filed and were filed
separately with the Securities and Exchange Commission.)
10.85 Underground Coal Sales Agreement, dated August 31, 2001
among San Juan Coal Company, the Company and Tucson
Electric Power Company. (Confidential treatment was
requested to portions of this exhibit, and such portions
were omitted from this exhibits filed and were filed
separately with the Securities and Exchange Commission.)
15.0 Letter Re: Unaudited Interim Financial Information
b. Reports on Form 8-K:
Report dated and filed August 16, 2001 reporting Regulators decline to
reconsider the Company's Holding Company Order.
Report dated and filed August 17, 2001 reporting the Company names Energy Risk
Management Strategist, R. Martin Chavez to Board of Directors.
Report dated and filed September 13, 2001 reporting the Company declares Common
and Preferred Stock Dividend.
Report dated and filed September 18, 2001 reporting the Company's Comparative
Operating Statistics for the month of August 2001 and 2000 and the year ended
August 31, 2001 and 2000.
Report dated and filed September 19, 2001 reporting the Company's Board of
Directors approves activation of New Holding Company, PNM Resources, Inc.
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Report dated and filed October 11, 2001 reporting the Company's Comparative
Operating Statistics for the month of September 2001 and 2000 and the year ended
September 30, 2001 and 2000.
Report dated and filed October 16, 2001 reporting the Company asked court to
rule on Western Resources Agreement and related complaint of PNM, HVOLT
Enterprises, Inc., HVK, Inc., and HVNM, Inc. Plaintiffs, vs. Western Resources,
Inc., Defendant.
Report dated and filed October 23, 2001 reporting the Company its Third Quarter
2001 Earnings Conference Call.
Report dated and filed October 25, 2001 reporting the Company Reports Quarter
and Nine Months Ended September 30, 2001 Earnings Announcement and Consolidated
Statement of Earnings.
Report dated and filed November 2, 2001 reporting the Company Merchant Utility
Model combines growth with Stability, Chief Executive Jeff Sterba Tells
Analysts.
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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: November 14, 2001 /s/ John R. Loyack
-----------------------------------------------
John R. Loyack
Vice President, Corporate Controller
and Chief Accounting Officer
(Officer duly authorized to sign this report)
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