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 March 31, 2002
--------------
- OR -
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _________________
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
- ----------- ----------------------------------- ------------------
333-32170 PNM Resources, Inc. 85-0468296
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
1-6986 Public Service Company of New Mexico 85-0019030
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
Securities Registered Pursuant To Section 12(b) Of The Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
- ---------- ------------------- ---------------------
PNM Resources, Inc. Common Stock, No Par Value New York Stock Exchange
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.
Registrant Class Outstanding at May 1, 2002
- ---------- ----- --------------------------
PNM Resources, Inc. Common Stock, No Par Value 39,117,799
PNM RESOURCES, INC. AND SUBSIDIARIES
INDEX
Page No.
PART I. FINANCIAL INFORMATION:
Report of Independent Public Accountants............................. 3
ITEM 1. FINANCIAL STATEMENTS
PNM Resources, Inc.
Consolidated Statements of Earnings
Three Months Ended March 31, 2002 and 2001................ 4
Consolidated Balance Sheets
Three Months Ended March 31, 2002 and December 31, 2001... 5
Consolidated Statements of Cash Flows
Three Months Ended March 31, 2002 and 2001................ 7
Consolidated Statements of Comprehensive Income
Three Months Ended March 31, 2002 and 2001................ 8
Public Service Company of New Mexico
Consolidated Statements of Earnings
Three Months Ended March 31, 2002 and 2001................ 9
Consolidated Balance Sheets
Three Months Ended March 31, 2002 and December 31, 2001... 10
Consolidated Statements of Cash Flows
Three Months Ended March 31, 2002 and 2001................ 12
Consolidated Statements of Comprehensive Income
Three Months Ended March 31, 2002 and 2001................ 13
Notes to Consolidated Financial Statements........................ 14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS............ 27
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.............................................. 57
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS........................................... 60
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................ 65
Signature ......................................................... 66
2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of PNM Resources, Inc. and Public Service Company of New Mexico:
We have reviewed the accompanying consolidated balance sheets and statements of
capitalization of PNM Resources, Inc. and Subsidiaries and the consolidated
balance sheets and statements of capitalization of Public Service Company of New
Mexico and Subsidiaries as of March 31, 2002, and the related consolidated
statements of earnings, cash flows and comprehensive income for the three-month
periods then ended. 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 sheets and statements of
capitalization of PNM Resources, Inc. and Subsidiaries and Public Service
Company of New Mexico and Subsidiaries as of December 31, 2001, and the related
consolidated statements of earnings, cash flows and comprehensive income for the
year then ended (not presented herein), and in our report dated February 1,
2002, we expressed an unqualified opinion on those financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheets as of December 31, 2001 is fairly stated, in all material respects, in
relation to the consolidated balance sheets from which it has been derived.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
May 15, 2002
3
ITEM 1. FINANCIAL STATEMENTS
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended
March 31,
----------------------------
2002 2001
------------- ------------
(In thousands, except
per share amounts)
Operating Revenues:
Electric...................................... $ 203,963 $544,594
Gas........................................... 109,201 191,936
Unregulated businesses........................ 832 -
------------- ------------
Total operating revenues.................... 313,996 736,530
------------- ------------
Operating Expenses:
Cost of energy sold........................... 155,108 497,098
Administrative and general.................... 32,064 39,488
Energy production costs....................... 34,971 35,025
Depreciation and amortization................. 24,779 24,219
Transmission and distribution costs........... 16,537 15,277
Taxes, other than income taxes................ 8,484 7,217
Income taxes.................................. 9,366 40,906
------------- ------------
Total operating expenses.................... 281,309 659,230
------------- ------------
Operating income............................ 32,687 77,300
------------- ------------
Other Income and Deductions
Other......................................... 12,230 4,560
Income tax expense............................ (4,842) (1,926)
------------- ------------
Net other income and deductions............. 7,388 2,634
------------- ------------
Income before interest charges.............. 40,075 79,934
------------- ------------
Interest charges................................ 15,126 16,382
------------- ------------
Net Earnings.................................... 24,949 63,552
Preferred Stock Dividend Requirements........... 146 146
------------- ------------
Net Earnings Applicable to Common Stock......... $ 24,803 $ 63,406
============= ============
Net Earnings per Common Share:
Basic......................................... $ 0.63 $ 1.62
============= ============
Diluted....................................... $ 0.63 $ 1.60
============= ============
Dividends Paid per Common Share................. $ 0.20 $ 0.20
============= ============
The accompanying notes are an integral part of these financial statements.
4
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2002 2001
--------------- --------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service..................................... $2,109,993 $2,118,417
Gas plant in service.......................................... 589,097 575,350
Common plant in service and plant held for future use......... 49,546 45,223
--------------- --------------
2,748,636 2,738,990
Less accumulated depreciation and amortization................ 1,254,787 1,234,629
--------------- --------------
1,493,849 1,504,361
Construction work in progress................................. 301,646 249,656
Nuclear fuel, net of accumulated amortization of
$19,533 and $16,954....................................... 25,817 26,940
--------------- --------------
Net utility plant........................................... 1,821,312 1,780,957
--------------- --------------
Other Property and Investments:
Other investments............................................. 440,082 552,453
Non-utility property, net of accumulated depreciation of
$1,623 and $1,580......................................... 1,742 1,784
--------------- --------------
Total other property and investments........................ 441,824 554,237
--------------- --------------
Current Assets:
Cash and cash equivalents..................................... 26,708 26,057
Accounts receivables, net of allowance for uncollectible
accounts of $17,425 and $18,025........................... 120,599 147,787
Other receivables............................................. 44,495 52,158
Inventories................................................... 37,259 36,483
Regulatory assets............................................. 2,740 10,473
Short-term investments........................................ 151,960 45,111
Other current assets.......................................... 31,956 31,428
--------------- --------------
Total current assets........................................ 415,717 349,497
--------------- --------------
Deferred Charges:
Regulatory assets............................................. 183,263 197,948
Prepaid benefit costs......................................... 38,724 18,273
Other deferred charges........................................ 46,556 33,726
--------------- --------------
Total current assets........................................ 268,543 249,947
--------------- --------------
$ 2,947,396 $ 2,934,638
=============== ==============
The accompanying notes are an integral part of these financial statements.
5
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2002 2001
--------------- ---------------
(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands)
Capitalization:
Common stockholders' equity:
Common stock................................................... $ 623,149 $ 625,632
Additional paid-in capital..................................... - -
Accumulated other comprehensive income, net of tax............. (26,422) (28,996)
Retained earnings.............................................. 431,586 415,388
--------------- ---------------
Total common stockholders' equity........................... 1,028,313 1,012,024
Minority interest................................................. 11,053 11,652
Cumulative preferred stock without mandatory
redemption requirements...................................... 12,800 12,800
Long-term debt, less current maturities........................... 953,897 953,884
--------------- ---------------
Total capitalization........................................ 2,006,063 1,990,360
--------------- ---------------
Current Liabilities:
Short-term debt.................................................... 93,800 35,000
Accounts payable.................................................... 99,592 120,918
Accrued interest and taxes.......................................... 53,050 72,022
Other current liabilities........................................... 87,711 101,697
--------------- ---------------
Total current liabilities................................... 334,153 329,637
--------------- ---------------
Deferred Credits:
Accumulated deferred income taxes................................... 120,359 120,153
Accumulated deferred investment tax credits......................... 43,931 44,714
Regulatory liabilities.............................................. 41,915 52,890
Regulatory liabilities related to accumulated deferred income tax... 14,163 14,163
Accrued postretirement benefit costs................................ 12,733 14,929
Other deferred credits.............................................. 374,079 367,792
--------------- ---------------
Total deferred credits....................................... 607,180 614,641
--------------- ---------------
$2,947,396 $2,934,638
=============== ===============
The accompanying notes are an integral part of these financial statements.
6
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
--------------------------------
2002 2001
-------------- --------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings.......................................................... $ 24,949 $ 63,552
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization..................................... 27,352 25,080
Other, net........................................................ (9,625) 6,462
Changes in certain assets and liabilities:
Accounts receivables............................................ 27,188 (33,388)
Other assets.................................................... (7,215) 23,630
Accounts payable................................................ (21,326) (40,075)
Accrued taxes................................................... (18,972) 49,621
Other liabilities............................................... (6,969) 14,630
-------------- --------------
Net cash flows provided from operating activities............... 15,382 109,512
-------------- --------------
Cash Flows Used for Investing Activities:
Utility plant additions............................................... (69,420) (55,820)
Return of principal of PVNGS lessor notes............................. 8,996 8,535
Other investing....................................................... (2,055) 109
-------------- --------------
Net cash flows used for investing activities.................... (62,479) (47,176)
-------------- --------------
Cash Flows Used for Financing Activities:
Borrowings............................................................ 58,800 -
Exercise of employee stock options.................................... (2,483) (476)
Dividends paid........................................................ (7,970) (7,965)
Other financing....................................................... (599) (285)
-------------- --------------
Net cash flows provided by (used for) financing activities...... 47,748 (8,726)
-------------- --------------
Increase in Cash and Cash Equivalents................................... 651 53,610
Beginning of Period..................................................... 26,057 107,691
-------------- --------------
End of Period........................................................... $ 26,708 $ 161,301
============== ==============
Supplemental Cash Flow Disclosures:
Interest paid......................................................... $ 16,183 $ 17,748
============== ==============
Capitalized interest.................................................. $ 1,740 $ -
============== ==============
Income taxes paid, net ............................................... $ 38,283 $ 3,400
============== ==============
The accompanying notes are an integral part of these financial statements.
7
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended
March 31,
----------------------------
2002 2001
------------- -------------
(In thousands)
Net Earnings............................................................ $24,949 $63,552
------------- -------------
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses) arising from the period......... 1,822 (948)
Less reclassification adjustment for gains (losses)
included in net income......................................... (430) (296)
Minimum pension liability adjustment................................ - 780
Mark-to-market adjustment for certain derivative transactions:
Initial implementation of SFAS 133 designated cash flow hedges.... - 6,148
Change in fair market value of designated cash flow hedges
Change in fair market value of designated cash flow hedges........ 615 9,715
Less reclassification adjustment for gains (losses)
in cash flow hedges............................................ 568 -
------------- -------------
Total Other Comprehensive Income........................................ 2,575 15,399
------------- -------------
Total Comprehensive Income.............................................. $27,524 $78,951
============= =============
The accompanying notes are an integral part of these financial statements.
8
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended
March 31,
---------------------------------
2002 2001
--------------- -------------
(In thousands, except
per share amounts)
Operating Revenues:
Electric..................................... $291,826 $544,594
Gas.......................................... 21,338 191,936
--------------- -------------
Total operating revenues................... 313,164 736,530
--------------- -------------
Operating Expenses:
Cost of energy sold.......................... 155,108 497,098
Administrative and general................... 27,825 39,488
Energy production costs...................... 34,971 35,025
Depreciation and amortization................ 24,773 24,219
Transmission and distribution costs.......... 16,537 15,277
Taxes, other than income taxes............... 8,036 7,217
Income taxes................................. 9,772 40,906
--------------- -------------
Total operating expenses................... 277,022 659,230
--------------- -------------
Operating income........................... 36,142 77,300
--------------- -------------
Other Income and Deductions
Other........................................ 11,046 4,560
Income tax expense........................... (4,373) (1,926)
--------------- -------------
Net other income and deductions............ 6,673 2,634
--------------- -------------
Income before interest charges............. 42,815 79,934
--------------- -------------
Interest charges............................... 17,961 16,382
--------------- -------------
Net Earnings................................... 24,854 63,552
Preferred Stock Dividend Requirements.......... 146 146
--------------- -------------
Net Earnings................................... $ 24,708 $ 63,406
=============== =============
The accompanying notes are an integral part of these financial statements.
9
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2002 2001
------------------ -----------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service..................................... $2,109,993 $2,118,417
Gas plant in service.......................................... 589,097 575,350
Common plant in service and plant held for future use......... 21,021 45,223
------------------ -----------------
2,720,111 2,738,990
Less accumulated depreciation and amortization................ 1,247,197 1,234,629
------------------ -----------------
1,472,914 1,504,361
Construction work in progress................................. 299,283 249,656
Nuclear fuel, net of accumulated amortization of
$19,533 and $16,954....................................... 25,817 26,940
------------------ -----------------
Net utility plant........................................... 1,798,014 1,780,957
------------------ -----------------
Other Property and Investments:
Other investments............................................. 435,660 446,784
Non-utility property, net of accumulated depreciation of
$1,580 for December 31, 2001.............................. 966 1,784
------------------ -----------------
Total other property and investments........................ 436,626 448,568
------------------ -----------------
Current Assets:
Cash and cash equivalents..................................... 23,008 14,677
Accounts receivables, net of allowance for uncollectible
accounts of $17,425 and $18,025........................... 120,599 147,787
Other receivables............................................. 42,211 52,158
Intercompany accounts receivable.............................. 39,336 -
Intercompany notes receivable................................. 2,800 -
Inventories................................................... 37,245 36,483
Regulatory assets............................................. 2,740 10,473
Short-term investments........................................ 45,407 45,111
Other current assets.......................................... 34,418 21,477
------------------ -----------------
Total current assets........................................ 347,764 328,166
------------------ -----------------
Deferred Charges:
Regulatory assets............................................. 170,284 187,475
Prepaid benefit costs......................................... 38,724 18,273
Other deferred charges........................................ 58,966 44,199
------------------ -----------------
Total current assets........................................ 267,974 249,947
------------------ -----------------
$2,850,378 $2,807,638
================== =================
The accompanying notes are an integral part of these financial statements.
10
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2002 2001
--------------- ---------------
(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands)
Capitalization:
Common stockholders' equity:
Common stock.................................................. $ 195,589 $ 195,589
Additional paid-in capital.................................... 430,043 430,043
Accumulated other comprehensive income, net of tax............ (27,521) (28,996)
Retained earnings............................................. 307,598 288,388
--------------- ---------------
Total common stockholders' equity.......................... 905,709 885,024
Minority interest................................................ 11,053 11,652
Cumulative preferred stock without mandatory
redemption requirements..................................... 12,800 12,800
Long-term debt, less current maturities.......................... 953,898 953,884
--------------- ---------------
Total capitalization....................................... 1,883,460 1,863,360
--------------- ---------------
Current Liabilities:
Short-term debt................................................. 93,800 35,000
Accounts payable................................................. 87,074 120,918
Intercompany accounts payable.................................... 20,515 -
Intercompany notes payable....................................... 10,346 -
Accrued interest and taxes....................................... 76,596 72,022
Other current liabilities........................................ 78,761 101,697
--------------- ---------------
Total current liabilities.................................. 367,092 329,637
--------------- ---------------
Deferred Credits:
Accumulated deferred income taxes.................................. 134,114 120,153
Accumulated deferred investment tax credits........................ 43,931 44,714
Regulatory liabilities............................................. 41,915 52,890
Regulatory liabilities related to accumulated deferred income tax.. 14,163 14,163
Accrued postretirement benefit costs............................... 13,613 14,929
Other deferred credits............................................. 352,090 367,792
--------------- ---------------
Total deferred credits.......................................... 599,826 614,641
--------------- ---------------
$2,850,378 $2,807,638
=============== ===============
The accompanying notes are an integral part of these financial statements.
11
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
----------------------------------
2002 2001
-------------- --------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings......................................................... $ 24,854 $ 63,552
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization.................................... 24,773 25,080
Other, net....................................................... 4,211 6,462
Changes in certain assets and liabilities:
Accounts receivables........................................... 27,188 (33,388)
Other assets................................................... 17,868 23,630
Accounts payable............................................... (33,844) (40,075)
Accrued taxes.................................................. (11,884) 49,621
Other liabilities.............................................. (17,137) 14,630
-------------- --------------
Net cash flows provided from operating activities.............. 36,029 109,512
-------------- --------------
Cash Flows Used for Investing Activities:
Utility plant additions.............................................. (67,966) (55,820)
Return on PVNGS lease obligation bonds............................... 8,996 8,535
Other investing...................................................... (2,055) 109
-------------- --------------
Net cash flows used for investing activities................... (61,025) (47,176)
-------------- --------------
Cash Flows Used for Financing Activities:
Borrowings........................................................... 58,800 -
Exercise of employee stock options................................... - (476)
Dividends paid....................................................... (17,284) (7,965)
Other financing...................................................... (520) (285)
Change in intercompany accounts...................................... (7,669) -
-------------- --------------
Net cash flows provided by (used by) financing activities...... 33,327 (8,726)
-------------- --------------
Increase in Cash and Cash Equivalents.................................. 8,331 53,610
Beginning of Period.................................................... 14,677 107,691
-------------- --------------
End of Period.......................................................... $ 23,008 $ 161,301
============== ==============
Supplemental Cash Flow Disclosures:
Interest paid........................................................ $ 16,183 $ 17,748
============== ==============
Capitalized interest................................................. $ 1,740 $ -
============== ==============
Income taxes paid, net .............................................. $ 31,514 $ 3,400
============== ==============
The accompanying notes are an integral part of these financial statements.
12
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended
March 31,
-----------------------------
2002 2001
------------- --------------
(In thousands)
Net Earnings............................................................. $ 24,854 $63,552
------------- --------------
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses) arising from the period.......... 1,383 (948)
Less reclassification adjustment for gains (losses)
included in net income.......................................... (430) (296)
Minimum pension liability adjustment................................. - 780
Mark-to-market adjustment for certain derivative transactions:
Initial implementation of SFAS 133 designated cash flow hedges
Change in fair market value of designated cash flow hedges......... - 6,148
Change in fair market value of designated cash flow hedges......... 615 9,715
Less reclassification adjustment for gains (losses)
in cash flow hedges............................................. 568 -
------------ --------------
Total Other Comprehensive Income......................................... 2,136 15,399
------------ --------------
Total Comprehensive Income............................................... $ 26,990 $78,951
============ ==============
The accompanying notes are an integral part of these financial statements.
13
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies and Responsibilities for Financial Statements
In the opinion of management of PNM Resources, Inc. (the "Company") and
Public Service Company of New Mexico ("PNM"), the accompanying interim
consolidated financial statements present fairly the Company's financial
position at March 31, 2002 and December 31, 2001, the consolidated results of
its operations for the three months ended March 31, 2002 and 2001 and the
consolidated statements of cash flows for the three months ended March 31, 2002
and 2001. 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, 2001, which are included on the Company's Annual Report on Form
10-K for the year ended December 31, 2001. The results of operations presented
in the accompanying financial statements are not necessarily representative of
operations for an entire year.
(2) Presentation
The Notes to the Consolidated Financial Statements of the Company and PNM
are presented on a combined basis. The Company as an unconsolidated holding
company ("Holding Company") assumed substantially all of the corporate
activities of PNM on December 31, 2001. These activities are billed to PNM on a
cost basis to the extent they are for the corporate management of PNM. In
January 2002, Avistar, Inc. ("Avistar") and certain inactive subsidiaries were
dividended to PNM Resources, Inc. pursuant to an order from the New Mexico
Public Regulatory Commission ("PRC"). The reader of the Notes to the
Consolidated Financial Statements should assume that the information presented
applies to consolidated results of operations and financial position of both the
Company and PNM, except where the context or references clearly indicate
otherwise. Discussions regarding specific contractual obligations generally
reference the company that is legally obligated. In the case of contractual
obligations of PNM, these obligations are consolidated with the Company under
Generally Accepted Accounting Principles. Broader operational discussion refers
to the Company.
Certain amounts in the 2001 consolidated financial statements and notes
have been reclassified to conform to the 2002 financial statement presentation.
(3) Segment Information
The Company is an investor-owned holding company of energy and energy
related companies. Its principal subsidiary, PNM, is an integrated public
utility primarily engaged in the generation, transmission, distribution and sale
and trading of electricity; transmission, distribution and sale of natural gas
within the State of New Mexico and the sale and trading of electricity in the
Western United States. The Company's wholly-owned subsidiary, Avistar, provides
unregulated energy services.
14
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Company, the Company became the parent company of PNM. Prior
to the share exchange, the Company had existed as a subsidiary of PNM. The new
holding company began trading on the New York Stock Exchange under the same PNM
symbol beginning on December 31, 2001.
As it currently operates, the Company's principal business segments are
Utility Operations, which include the Electric Services ("Electric") and the Gas
Services ("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.
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 2,890
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.
Electric exclusively acquires its electricity sold to retail customers
from the Company's Generation and Trading Operations. 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.
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.
In the first quarter of 2001, the Company's Generation and Trading
Operations procured its gas fuel supply from Gas. In the second quarter of 2001,
the Company's Generation and Trading Operations began procuring its gas supply
independent of Gas and contracting with Gas for transportation services only.
15
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. In addition to generation capacity, the Company purchases
power in the open market. As of March 31, 2002 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.
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 and
non-utility businesses. Unregulated also includes immaterial corporate
activities and eliminations. The immaterial corporate activities were assumed by
the Company on December 31, 2001.
RISKS AND UNCERTAINTIES
The Company's future results may be affected by changes in regional
economic conditions; the outcome of labor negotiations with unionized employees;
fluctuations in fuel, purchased power and gas prices; the actions of utility
regulatory commissions; changes in law and environmental regulations, the
success of its planned generation expansion 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. The
Company's future results will be impacted by its ability to recover its stranded
costs, incurred previously in providing power generation to electric service
customers, the market price of electricity and natural gas costs and the costs
of transition to an unregulated status. In addition, as a result of
deregulation, the Company may face competition from companies with greater
financial and other resources.
16
Summarized financial information by business segment for the three months
ended March 31, 2002 and 2001 is as follows:
Utility
------------------------------- Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2002:
Operating revenues:
External customers............ $135,243 $ 109,086 $244,329 $ 68,720 $ 832 $313,881
Intersegment revenues......... 177 115 292 81,950 (82,127) 115
Depreciation and amortization.... 8,555 5,312 13,867 10,907 5 24,779
Interest income.................. 318 88 406 402 15,451 16,259
Net interest charges............. 5,835 3,318 9,153 3,468 2,505 15,126
Income tax expense
From continuing operations..... 5,936 5,711 11,647 1,301 1,260 14,208
Operating income (loss).......... 15,017 12,093 27,110 5,623 (46) 32,687
Segment net income (loss)........ 9,059 8,714 17,773 1,985 5,191 24,949
Total assets..................... 762,747 457,934 1,220,681 1,418,564 308,151 2,947,396
Gross property additions......... 12,856 6,543 19,399 48,545 1,476 69,420
Utility
------------------------------ Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2001:
Operating revenues:
External customers............. $134,346 $190,686 $325,032 $410,248 $ - $735,280
Intersegment revenues.......... 177 1,250 1,427 80,917 (81,094) 1,250
Depreciation and amortization..... 8,025 5,290 13,315 10,895 9 24,219
Interest income................... 457 286 743 12,625 1,831 15,199
Net interest charges.............. 4,273 2,985 7,258 9,094 30 16,382
Income tax expense (benefit)
from continuing operations...... 6,899 5,162 12,061 35,183 (4,412) 42,832
Operating income (loss)........... 14,526 10,507 25,033 58,106 (5,839) 77,300
Segment net income (loss)......... 10,410 7,736 18,146 53,596 (8,190) 63,552
Total assets...................... 724,513 517,412 1,241,925 1,538,209 216,920 2,997,054
Gross property additions.......... 11,440 6,574 18,014 36,342 1,464 55,820
(4) Financial Instruments
The Company uses derivative financial instruments to manage risk as it
relates to changes in natural gas and electric prices, interest rates of future
debt issuances 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.
17
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company is exposed to credit risk in the event of non-performance or
non-payment by counterparties of its financial derivative instruments. The
Company uses a credit management process to assess and monitor the financial
conditions of counterparties. The Company's credit risk with its largest
counterparty as of March 31, 2002 was $4.3 million.
Natural Gas Contracts
Pursuant to a 1997 order issued by the NMPUC, predecessor to the PRC, PNM
has previously entered into various financial instruments to hedge certain
portions of natural gas supply contracts in order to protect PNM's natural gas
customers from the risk of adverse price fluctuations in the natural gas market.
The financial impact of all hedge gains and losses from these instruments is
recoverable through PNM's purchased gas adjustment clause as deemed prudently
incurred by the PRC. As a result, earnings are not affected by gains or losses
generated by these instruments.
PNM purchased gas options, a type of hedge, to protect its natural gas
customers from price risk during the 2001-2002 heating season. PNM expended $9.4
million to purchase options that limit the maximum amount PNM would pay for gas
during the winter heating season. PNM recovered its actual hedging expenditures
as a component of the PGAC during the months of October 2001 through February
2002 in equal allotments of $1.88 million. As winter 2001-2002 gas prices were
substantially lower than the previous year, the hedges placed for this winter
expired unexercised.
PNM also purchased gas options for the 2002-2003 heating season. PNM
expended $6.0 million to purchase options that limit the maximum amount PNM
would pay for gas during the winter heating season. PNM plans to recover its
actual hedging expenditures as a component of the PGAC during the months of
October 2002 through February 2003 in equal allotments of $1.2 million.
Electricity Trading Contracts
For the three months ended March 31, 2002, the Company's Generation and
Trading Operations settled trading contracts for the sale of electricity that
generated $7.8 million of electric revenues by delivering 222,096 MWh. The
Company purchased $17.0 million or 276,896 MWh of electricity to support these
contractual sales and other open market sales opportunities. For the three
months ended March 31, 2001, the Company's Generation and Trading Operations
settled trading contracts for the sale of electricity that generated $11.8
million of electric revenues by delivering 122,000 MWh. The Company purchased
$10.9 million or 102,400 MWh of electricity to support these contractual sales
and other open market sales opportunities.
As of March 31, 2002, the Company had open trading contract positions to
buy $63.0 million and to sell $31.2 million of electricity. At March 31, 2002,
the Company had a gross mark-to-market gain (asset position) on these trading
contracts of $7.6 million and gross mark-to-market loss (liability position) of
$28.5 million, with net mark-to-market loss (liability position) of $20.9
million. The change in mark-to-market valuation is recognized in earnings each
period.
18
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 March
31, 2002, the Company had open forward positions classified as normal sales of
electricity of $16.3 million and normal purchases of electricity of $42.9
million.
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.
Forward Starting Interest Rate Swaps
PNM currently has $182.0 million of tax-exempt bonds outstanding that are
callable at a premium in December 2002 and August 2003. PNM intends to refinance
these bonds assuming the interest rate of the refinancing does not exceed the
current interest rate of the bonds and has hedged the entire planned
refinancing. In order to take advantage of current low interest rates, PNM
entered into two forward starting interest rate swaps in November and December
2001 and three additional contracts in the first quarter of 2002. PNM designated
these swaps as cash flow hedges. The hedged risks associated with these
instruments are the changes in cash flows related to general moves in interest
rates expected for the refinancing. The swaps effectively cap the interest on
the refinancing to 4.9% plus an adjustment for PNM's and the industry's credit
rating. PNM's assessment of hedge effectiveness is based on changes in the
interest rates and PNM's credit spread. 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 transactions affect earnings. Any
hedge ineffectiveness is required to be presented in current earnings. There was
no material hedge ineffectiveness in the three months ended March 31, 2002.
A forward starting swap does not require any upfront premium and captures
changes in the corporate credit component of an investment grade company's
interest rate as well as the underlying Treasury benchmark. The five forward
interest rate starting swaps have termination dates and notional amounts as
follows: one with a termination date of September 17, 2002 for a notional amount
of $46.0 million and four with a termination date of May 15, 2003 for a combined
notional amount of $136.0 million. There were no fees on the transaction, as
they are imbedded in the rates, and the transactions will be cash settled on the
mandatory unwind date (strike date), corresponding to the refinancing date of
the underlying debt. The settlement will be capitalized as a cost of issuance
and amortized over the life of the debt as a yield adjustment.
19
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(5) Earnings Per Share
In accordance with SFAS No. 128, Earnings per Share, dual presentation of
basic and diluted earnings per share has been presented in the Consolidated
Statements of Earnings. The following reconciliation illustrates the impact on
the share amounts of potential common shares and the earnings per share amounts
for March 31 (in thousands except per share amounts):
Three Months Ended
March 31,
2002 2001
----------- -----------
Basic:
Net Earnings from Continuing Operations................ $ 24,949 $ 63,552
----------- -----------
Net Earnings........................................... 24,949 63,552
Preferred Stock Dividend Requirements.................. 146 146
----------- -----------
Net Earnings Applicable to Common Stock................ $ 24,803 $ 63,406
=========== ===========
Average Number of Common Shares Outstanding............ 39,118 39,118
=========== ===========
Net Earnings per Common Share (Basic).................. $ 0.63 $ 1.62
=========== ===========
Diluted:
Net Earnings Applicable to Common Stock
Used in basic calculation............................ $ 24,803 $ 63,406
=========== ===========
Average Number of Common Shares Outstanding............ 39,118 39,118
Dilutive effect of common stock equivalents (a)........ 531 481
----------- -----------
Average common and common equivalent shares
Outstanding.......................................... 39,649 39,599
=========== ===========
Net Earnings per Share of Common Stock (Diluted)....... $ 0.63 $ 1.60
=========== ===========
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out-of-the-money options of 14,000 for the three months ended
March 31, 2002. There were no anti-dilutive common stock equivalents in
2001.
20
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies
Construction Commitment
PNM has committed to purchase five combustion turbines for a total cost
of $151.3 million. The turbines are for planned power generation plants with an
estimated cost of construction of approximately $370 million. PNM has expended
$160 million as of March 31, 2002 of which $117.2 million was for equipment
purchases. In November 2001, PNM broke ground to build Afton Generating Station,
a 135 MW single cycle gas turbine plant in Southern New Mexico. In February
2002, PNM broke ground to build Lordsburg Generating Station ("Lordsburg"), an
80 MW natural gas fired generating plant in Southern New Mexico. In January of
2002, the Lordsburg City Council approved the issuance of industrial revenue
bonds for Lordsburg. Contracts have not been finalized on the remaining planned
construction. These plants are part of the Company's ongoing competitive
strategy of increasing generation capacity over time. This construction is not
anticipated to be added to rate base.
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.
Aspects of the Federal law referred to above (the "Price-Anderson Act"),
which provides for payment of public liability claims in case of a catastrophic
accident involving a nuclear power plant are up for renewal in August 2002.
While existing nuclear power plant would continue to be covered in any event,
the renewal would extend coverage to future nuclear power plants and could
contain amendments that would affect existing plants. A renewal bill was passed
by the House with unanimous consent on November 27, 2001. The House proposed a
change in the annual retrospective premium limit from $10 million to $15 million
per reactor per incident. Additionally, the House proposed to amend the maximum
potential assessment from $88.1 million to $98.7 million per reactor per
incident, taking into account effects of inflation. On March 7, 2002 the Senate
approved a Price-Anderson Act amendment as a part of the overall energy bill.
The Senate version is substantially the same as the Price-Anderson Act in its
current form. In the event the energy bill does not pass, it is possible that
the Price-Anderson amendment would be passed as a stand-alone bill. In a report
issued in 1998, the Nuclear Regulatory Commission ("NRC") had made a number of
recommendations regarding the Price-Anderson Act, including a recommendation
that Congress investigate whether the $200 million now available from the
private insurance market for liability claims per reactor could be increased to
keep pace with inflation. The Company cannot predict whether or not Congress
will renew the Price-Anderson Act or act on the NRC's recommendation. However,
21
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
if adopted, certain changes in the law 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, 2002, a
substantial portion of which must be applied to stabilization and
decontamination. The Company has also secured insurance against portions of the
increased cost of generation or purchased power and business interruption
resulting from certain accidental outages of any of the three units if the
outages exceed 12 weeks. The insurance coverage discussed in this section is
subject to certain policy conditions and exclusions. The Company is a member of
an industry mutual insurer. This mutual insurer provides both the "all-risk" and
increased cost of generation insurance to the Company. In the event of adverse
losses experienced by this insurer, the Company is subject to an assessment. The
Company's maximum share of any assessment is approximately $4.8 million per
year.
PVNGS Decommissioning Funding
The Company has a program for funding its share of decommissioning costs
for PVNGS. The nuclear decommissioning funding program is invested in equities
and fixed 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 would be approximately
$181 million (in 1998 dollars). The estimated market value of the trusts at the
end of March 31, 2002 was approximately $58 million.
The Company did not provide any additional funding for the three months
ended March 31, 2002 into the qualified and non-qualified trust funds.
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 such 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
22
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 $ 41.0 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.
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 Company's investigation indicates that the
leak was an isolated incident likely caused by a combination of corrosion and
increased pressure. The Company also is cooperating with an investigation of the
incident by the PRC's Pipeline Safety Bureau, which issued its report on March
18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the
New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the
Company by the injured persons along with 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 as a result of the Pipeline Safety Bureau's investigation.
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.
Western Resources Transaction
On November 9, 2000, the Company and Western Resources announced that
both companies' Boards of Directors approved an agreement under which the
Company would acquire the Western Resources electric utility operations in a
tax-free, stock-for-stock transaction. The agreement required that Western
Resources split-off its non-utility businesses to its shareholders prior to
closing.
In July, 2001, the Kansas Corporation Commission ("KCC") issued two
orders. The first order declared the split-off required by the agreement to be
unlawful as designed, with or without a merger. The second order decreased rates
for Western Resources, despite a request for $151 million increase. After
rehearing the KCC established the rate decrease at $15.7 million. On October 3,
2001, the KCC issued an Order on Reconsideration reaffirming its decision that
the split-off as designed in the agreement was unlawful with or without a
merger.
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
23
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001 in New York state court
seeking declarations that the transaction could not be accomplished as 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 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.
On November 19, 2001, Western Resources filed a complaint against the
Company in New York state court alleging breach of contract and breach of
implied covenant of good faith and fair dealing. Western Resources alleged that
the Company brought about the KCC orders, failed to assist in efforts to reverse
the KCC orders, refused to renegotiate within the terms of the agreement,
interfered with Western Resources' efforts to satisfy the terms of the
agreement, and effected an unauthorized de facto termination of the agreement by
filing its complaint. Western Resources alleges damages in excess of $650
million. The Company believes that the complaint filed by Western Resources is
without merit and intends to vigorously defend itself against the complaint. The
Company also intends to vigorously pursue its own complaint.
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect.
On February 5, 2002, the District Court for Shawnee County, Kansas,
dismissed without prejudice Western Resources' appeal of the KCC's split-off
orders. The Court ruled that, by filing a new financial plan in compliance with
the orders, Western Resources accepted certain portions of the orders thereby
creating a situation where further administrative action became necessary. As a
result, the Court concluded that the matter was not ripe for judicial review and
remanded the case to the KCC.
On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate
order. On April 8, 2002, Western Resources filed with the Kansas Supreme Court a
Petition for Review of the Court of Appeals decision.
On May 2, 2002, the New York court issued an order denying Western
Resources' motion for stay or dismissal of the Company's complaint. At the same
time, the court granted the Company's motion to dismiss Western Resources'
complaint, without prejudice. As a result, the Company has been determined to be
the plaintiff in the litigation but Western Resources will be allowed, when it
files its answer, to reassert its claims against the Company as affirmative
defenses or counterclaims, if it so chooses.
On May 10, 2002, the Company filed an Amended Complaint seeking
unspecified damages from Western Resources for numerous breaches of contract
related to the determination that the split-off required by the agreement was
unlawful and required prior approval by the KCC. The Company also seeks
unspecified damages for additional breaches of contract because: Western
Resources failed to provide the Company with the opportunity to review and
comment on information related to the transaction provided by Western Resources
24
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
to third parties; Western Resources failed to obtain the Company's consent to
amend existing employee compensation and benefits plans or create new ones; and
Western Resources filed for approval of an alternative debt reduction plan that
represents the abandonment of the split-off required by the agreement. In
addition the Company seeks numerous declarations from the court, including that
the Company was not obligated to perform because conditions regarding
performance were not satisfied; the Company did not breach when it terminated
the agreement; and the rate case order constitutes a material adverse effect
under the terms of the agreement.
The Company is unable to predict the ultimate outcome of its litigation
with Western Resources.
Other
There are various claims and lawsuits pending against the Company and
certain of its subsidiaries. The Company is also subject to Federal, state and
local environmental laws and regulations, and is currently participating in the
investigation and remediation of numerous sites. In addition, the Company
periodically enters into financial commitments in connection with business
operations. It is not possible at this time for the Company to determine fully
the effect of all litigation on its consolidated financial statements. However,
the Company has recorded a liability where the litigation effects can be
estimated and where an outcome is considered probable. The Company does not
expect that any known lawsuits, environmental costs and commitments will have a
material adverse effect on its financial condition or results of operations.
(7) Environmental Issues
The normal course of operations of the Company necessarily involves
activities and substances that expose the Company to potential liabilities under
laws and regulations protecting the environment. Liabilities under these laws
and regulations can be material and in 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).
25
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 three months ended March 31, 2002 and 2001, the Company spent
$1.3 million and $1.4 million, respectively, for remediation. The majority of
the March 31, 2002 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) New and Proposed Accounting Standards
Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" ("SFAS 143"). In June 2001, the 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, 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
The Management's Discussion and Analysis of Financial Condition and
Results of Operations for PNM Resources, Inc. (the "Company") and Public Service
Company of New Mexico ("PNM") is presented on a combined basis. The Company as
an unconsolidated holding company ("Holding Company") assumed substantially all
of the corporate activities of PNM on December 31, 2001. These activities are
billed to PNM on a cost basis to the extent they are for the corporate
management of PNM. In January 2002, Avistar and certain inactive subsidiaries
were dividended to PNM Resources, Inc. pursuant to an order from the PRC. The
reader of this Management's Discussion and Analysis of Financial Condition and
Results of Operations should assume that the information presented applies to
consolidated results of operations and financial position of both the Company
and PNM, except where the context or references clearly indicate otherwise.
Discussions regarding specific contractual obligations generally reference the
company that is legally obligated. In the case of contractual obligations of
PNM, these obligations are consolidated with the Company under Generally
Accepted Accounting Principles ("GAAP"). Broader operational discussion
references the Company.
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 its annual report on Form 10-K for the year ended
December 31, 2001. Trends and contingencies of a material nature are discussed
to the extent known and considered relevant.
OVERVIEW
The Company is an investor-owned holding company of energy and energy
related companies. Its principal subsidiary, PNM, is an integrated public
utility primarily engaged in the generation, transmission, distribution and sale
and trading of electricity; transmission, distribution and sale of natural gas
within the State of New Mexico and the sale and trading of electricity in the
Western United States. The Company's principal business segments are Utility
Operations, which include Electric Services ("Electric") and Gas Services
("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 business line. The
Company's wholly-owned subsidiary, Avistar, Inc. ("Avistar"), provides
unregulated energy services.
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Company, the Company became the parent company of PNM. Prior
to the share exchange, the Company had existed as a subsidiary of PNM. The new
holding company began trading on the New York Stock Exchange under the same PNM
symbol beginning on December 31, 2001.
27
COMPETITIVE STRATEGY
The Company is positioned as a "merchant utility," primarily operating as
a regulated energy service provider also engaged in the sale and trading of
electricity in the competitive energy market place. As a utility, the Company
has an obligation to serve its customers under the jurisdiction of the New
Mexico Public Regulation Commission ("PRC"). As a merchant, the Company markets
excess production from the utility, as well as unregulated generation and its
purchases for resale into a competitive market place. The merchant operations
utilize an asset-backed trading strategy, whereby the Company's aggregate net
open position for the sale of electricity is covered by the Company's excess
generation capabilities. The benefits of the merchant operations are shared with
retail customers based on a negotiated settlement in proportion to capacity
owned, expended effort, and risk assumed. Non-regulated assets may be part of
the utility company or owned by an affiliate of the utility company, which could
be a subsidiary of the holding company. Currently, all non-regulated assets,
except Avistar, are part of the utility. Both retail customers and shareholders
benefit from this combination.
The Electric and Gas Services strategy is directed at supplying
reasonably priced and reliable energy to retail customers through customer
driven operational excellence, quality processes, and improved overall
organizational performance.
The Generation and Trading strategy calls for increased asset-backed
trading and generation capacity supported by long-term contracts, as well as
improved risk management strategies. The Company's plans to increase generation
calls for approximately 50% of its new generation and 70% of its total portfolio
to be committed through long-term contracts, including its sales to
jurisdictional customers. Such growth will be dependent on market developments,
and upon the Company's ability to generate funds for the Company's expansion.
(Intentionally left blank)
28
RESULTS OF OPERATIONS
Three Months Ended March 31, 2002
Compared to Three Months Ended March 31, 2001
Consolidated
The Company's net earnings available to common shareholders for the three
months ended March 31, 2002 were $24.8 million, a 60.9% decrease in net earnings
of $63.4 million in 2001. This decrease primarily reflects the slowdown in the
wholesale electric market, where both prices and trading activity were lower
than the prior year period. Despite the slow-down in the wholesale electricity
market, the Company's utility operations continued to perform strongly and
recorded operating income growth of 18%. This growth came from a combination of
load growth and cost savings, demonstrating the balance the regulated utility
provides in the Company's "merchant utility" strategy.
Earnings in 2001 were affected by certain non-recurring charges. These
special items are detailed in the individual business segment discussions below.
The following table enumerates these non-recurring charges and shows their
effect on diluted earnings per share, in thousands, except per share amounts.
Three Months Ended
March 31,
------------------------------------------------------------
2002 2001
---------------------------- ------------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
-------------- ------------- --------------- --------------
(Income)/Expense
Net Earnings Available for Common
Shareholders............................. $ 24,803 $0.63 $ 63,406 $1.60
-------------- ------------- --------------- --------------
Adjustment for Special Gains and Charges
(net of income tax effects):
Write-off of Avistar investments.......... - - 4,981 0.13
Western Resources acquisition costs....... - - 1,817 0.05
-------------- ------------- -------------- --------------
Total................................... - - 6,798 0.18
-------------- ------------- -------------- --------------
Net Earnings Available For Common
Shareholders Excluding Special Gains
and Charges $ 24,803 $0.63 $ 70,204 $1.78
============== ============= ============== ==============
To adjust reported net earnings and diluted earnings per share to exclude
the non-recurring charges, non-recurring charges, net of income tax benefit, are
added back to reported net earnings under GAAP.
29
The following discussion is based on the financial information presented
in the Consolidated Financial Statements - Segment Information note in the Notes
to the Consolidated Financial Statements.
Utility Operations
Electric
The table below sets forth the operating results for the Electric
business segment.
Electric
Three Months Ended March 31,
----------------------------------
2002 2001 Variance
------------- -------------- --------------
Operating revenues:
External customers............................. $135,243 $134,346 $ 897
Intersegment revenues.......................... 177 177 -
------------- -------------- --------------
Total revenues................................. 135,420 134,523 897
------------- -------------- --------------
Cost of energy sold.............................. 1,192 1,560 (368)
Intersegment purchases........................... 81,950 80,917 1,033
------------- -------------- --------------
Total cost of energy........................... 83,142 82,477 665
------------- -------------- --------------
Gross margin..................................... 52,278 52,046 232
------------- -------------- --------------
Administrative and general....................... 8,372 10,266 (1,894)
Corporate costs.................................. 2,403 1,566 837
Energy production costs.......................... 229 310 (81)
Depreciation and amortization.................... 8,555 8,025 530
Transmission and distribution costs.............. 8,512 8,107 405
Taxes other than income taxes.................... 3,173 2,527 646
Income taxes..................................... 6,017 6,719 (702)
------------- -------------- --------------
Total non-fuel operating expenses.............. 37,261 37,520 (259)
------------- -------------- --------------
Operating income................................. $ 15,017 $ 14,526 $ 491
------------- -------------- --------------
Operating revenues increased $0.9 million or 0.7% for the period to
$135.4 million. Retail electricity delivery grew 1.2% to 1.74 million MWh in
2002 compared to 1.72 million MWh delivered in the prior year period, resulting
in increased revenues of $2.2 million year-over-year. This volume increase was
the result of consistent load growth from economic expansion in New Mexico. This
increase was partially offset by lower revenue from property leasing.
(Intentionally left blank)
30
The following table shows electric revenues by customer class and average
customers:
Electric Revenues
(Thousands of dollars)
Three Months Ended
March 31,
----------------------------
2002 2001
------------- ------------
Residential..................... $50,722 $49,197
Commercial...................... 55,005 54,137
Industrial...................... 19,628 19,837
Other........................... 10,065 11,352
------------- ------------
$135,420 $134,523
============= ============
Average Customers............... 382,000 375,000
============= ============
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
Three Months Ended
March 31,
-----------------------------
2002 2001
------------ ------------
Residential..................... 588,996 572,199
Commercial...................... 711,259 713,198
Industrial...................... 392,346 388,135
Other........................... 46,874 45,033
------------ ------------
1,739,475 1,718,565
============ ============
The gross margin, or operating revenues minus cost of energy sold,
increased $0.2 million, which reflects the increased energy sales. Electric
exclusively purchases power from Generation and Trading at Company developed
prices which are not based on market rates. These intercompany revenues and
expenses are eliminated in the consolidated results.
Administrative and general costs decreased $1.9 million or 18.4% for the
period. This decrease was primarily due to lower bad debt expense as a result of
losses recognized in the prior year from the bankruptcy of a significant
customer that did not recur in 2002 and decreased pension and post-retirement
benefits expense. In 2001, the Company's pension and post-retirement benefits
expense was significantly higher than what the Company historically experienced
due to lower expected investment returns on plan assets. As a result of more
normal expected investment returns and the Company's cash contributions of $23.5
million to its plans in January 2002, pension and post retirement benefits
expense in 2002 was substantially reduced as compared to 2001.
Depreciation and amortization increased $0.5 million or 6.6% for the
period due to a higher depreciable plant base.
31
Transmission and distribution costs increased $0.4 million or 5.0%
primarily due to an increase in maintenance activities on station equipment and
overhead lines.
Taxes other than income increased $0.6 million or 25.6% primarily
reflecting adjustments recorded in the prior year for favorable audit outcomes
by certain tax authorities.
Gas
The table below sets forth the operating results for the Gas business
segment.
Gas
Three Months Ended March 31,
-------------------------------
2002 2001 Variance
------------- -------------- --------------
perating revenues:
External customers............................. $109,086 $190,686 $(81,600)
Intersegment revenues.......................... 115 1,250 (1,135)
------------- -------------- --------------
Total revenues................................. 109,201 191,936 (82,735)
------------- -------------- --------------
Total cost of energy........................... 64,749 148,472 (83,723)
------------- -------------- --------------
Gross margin..................................... 44,452 43,464 988
------------- -------------- --------------
Administrative and general....................... 8,648 12,349 (3,701)
Corporate costs.................................. 2,145 1,307 838
Energy production costs.......................... 531 431 100
Depreciation and amortization.................... 5,312 5,290 22
Transmission and distribution costs.............. 7,930 7,056 874
Taxes other than income taxes.................... 2,043 1,596 447
Income taxes..................................... 5,750 4,928 822
------------- -------------- --------------
Total non-fuel operating expenses.............. 32,359 32,957 (598)
------------- -------------- --------------
Operating income................................. $ 12,093 $10,507 $ 1,586
------------- -------------- --------------
Operating revenues decreased $82.7 million or 43.1% for the period to
$109.2 million, primarily as the result of lower natural gas prices during the
first quarter of 2002 as compared to the same period in the previous year. The
Company purchases natural gas in the open market and resells it at cost to its
distribution customers. As a result, increases or decreases in gas revenues
driven by gas costs do not impact the Company's gross margin or earnings. Gas
sales volumes decreased 5.0% contributing to the decreased revenues. However,
residential and commercial volume increased 10.8% due to load growth from
economic expansion in New Mexico.
(Intentionally left blank)
32
The following table shows gas revenues by customer and average customers:
Gas Revenues
(Thousands of dollars)
Three Months Ended
March 31,
------------------------------
2002 2001
------------- -------------
Residential....................... $72,112 $121,589
Commercial........................ 22,399 36,797
Industrial........................ 649 13,537
Transportation*................... 3,611 4,002
Other............................. 10,430 16,011
------------- -------------
$109,201 $191,936
============= =============
Average customers................. 444,000 435,000
============= =============
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
Three Months Ended
March 31,
-----------------------------
2002 2001
------------ ------------
Residential........................ 13,516 12,481
Commercial......................... 4,970 4,207
Industrial......................... 172 1,980
Transportation*.................... 7,397 9,178
Other.............................. 1,990 1,667
------------ ------------
28,045 29,513
============ ============
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold,
increased $1.0 million or 2.3%. This increase is due mainly to residential and
commercial customer load growth in the New Mexico service territory.
Administrative and general costs decreased $3.7 million or 30.0%. This
decrease is primarily due to lower bad debt expense as a result of losses
recognized in the prior year from the bankruptcy of a significant customer that
did not recur in 2002 and the decreased pension and post-retirement benefits as
discussed earlier.
Transmission and distribution costs increased $0.9 million or 12.4 %
primarily due to the timing of certain maintenance costs that are typically
incurred in the summer months. It is expected that the Company's maintenance
costs will be lower in the summer months.
33
Generation and Trading Operations
The table below sets forth the operating results for the Generation and
Trading business segment.
Generation and Trading
Three Months Ended March 31,
-------------------------------------
2002 2001 Variance
------------- -------------- --------------
Operating revenues:
External customers............................. $ 68,720 $410,248 $(341,528)
Intersegment revenues.......................... 81,950 80,917 1,033
------------- -------------- --------------
Total revenues................................. 150,670 491,165 (340,495)
------------- -------------- --------------
Cost of energy sold.............................. 89,167 347,066 (257,899)
Intersegment purchases........................... 177 177 -
------------- -------------- --------------
Total cost of energy........................... 89,344 347,243 (257,899)
------------- -------------- --------------
Gross margin..................................... 61,326 143,922 (82,596)
------------- -------------- --------------
Administrative and general....................... 4,153 5,120 (967)
Corporate costs.................................. 2,105 1,365 740
Energy production costs.......................... 34,211 34,284 (73)
Depreciation and amortization.................... 10,907 10,895 12
Transmission and distribution costs.............. 95 113 (18)
Taxes other than income taxes.................... 2,820 1,921 899
Income taxes..................................... 1,412 32,118 (30,706)
------------- -------------- --------------
Total non-fuel operating expenses.............. 55,703 85,816 (30,113)
------------- -------------- --------------
Operating income................................. $ 5,623 $58,106 $(52,483)
------------- -------------- --------------
Operating revenues declined $340.5 million or 69.3% for the period to
$150.7 million. This decrease in wholesale electricity sales primarily reflects
the slowdown in the wholesale electric market, where both prices and trading
activity were lower than the prior year period. Lower trading activity
experienced by Generation and Trading was also due to decreased plant
availability which resulted in lost market potential. The Company's plants'
capacity was 11.6% less than the prior year due to various unplanned outages.
The Company delivered wholesale (bulk) power of 4.1 million MWh of electricity
for the first quarter of 2002, compared to 4.9 million MWh for the same period
in 2001. Wholesale revenues from third-party customers decreased from $410.7
million to $56.3 million, an 86.3% decrease.
(Intentionally left blank)
34
The following table shows revenues by customer class:
Generation and Trading Revenues By Market
(Thousands of dollars)
Three Months Ended
March 31,
--------------------------------
2002 2001
--------------- ---------------
Intersegment sales.................. $ 81,950 $ 80,917
Long-term contract.................. 14,337 28,814
Trading*............................ 51,476 378,051
Other............................... 2,907 3,383
--------------- ---------------
$ 150,670 $ 491,165
=============== ===============
*Includes mark-to-market gains/(losses).
The following table shows sales by customer class:
Generation and Trading Sales By Market
(Megawatt hours)
Three Months Ended
March 31,
-------------------------------
2002 2001
------------- --------------
Intersegment sales.................. 1,739,475 1,718,565
Long-term contract.................. 281,153 478,053
Trading............................. 2,060,242 2,680,078
------------- --------------
4,080,870 4,876,696
============= ==============
The gross margin, or operating revenues minus cost of energy sold,
decreased $82.6 million or 57.4%. Lower margins were created primarily by weak
pricing, less price volatility and lower trading liquidity - the opportunity to
buy and resell power profitably in the marketplace. Trading liquidity was
negatively impacted in the first quarter of 2002 due to the bankruptcy of a
major trader in 2001, the price caps imposed by the Federal Energy Regulation
Commission ("FERC") and the Company's plant availability. Although the wholesale
market showed some forward price improvement towards the end of the quarter the
Company was unable to take advantage of this due to plant availability. These
lower margins were partially offset by an increase in unrealized mark-to-market
gains of $5.7 million period-over-period which the Company recognized relating
to its power trading contracts.
Administrative and general costs decreased $1.0 million or 18.9% for the
period. This decrease is primarily due to adjustments to prior year San Juan
Generating Station ("SJGS") participant billings (the Company is the operator of
SJGS) and the lower pension and post-retirement benefits expense discussed
earlier.
35
Energy production costs remained relatively constant in 2002 as compared
to 2001. The Company experienced significant costs related to various planned
and unplanned outages at SJGS, Palo Verde Generating Station ("PVNGS") and Four
Corners Power Plant ("Four Corners"). However, the Company was able to benefit
from the acceleration of its usual first quarter outage in the third quarter of
2001. In addition, these costs were offset by adjustments to prior year billings
for estimated costs by the PVNGS operator of $3.7 million.
Taxes other than income increased $0.9 million or 46.8% reflecting
adjustments recorded in the prior year for favorable audit outcomes by certain
tax authorities.
Unregulated Businesses
In July 2001, the Board of Directors of Avistar decided to wind down all
unregulated operations except for Avistar's Reliadigm business unit, which
provides maintenance solutions and technologies to the electric power industry.
In addition, the transfer of operation of the Sangre de Cristo Water Company 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. These
write-downs reflect the significant decline in the technology market and
bankruptcy of these investees. The Company recorded non-operating charges of
$8.3 million for the three months ended March 31, 2001 to reflect these
activities and the impairment of its Avistar investments. This charge was
recorded in other income and deductions.
Operating losses for Avistar decreased from $1.3 million in the prior
period to $0.4 million in the current period primarily due to decreased costs as
a result of the shutdown of certain operations.
Corporate
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, decreased $0.2 million for
the period to $9.6 million. This decrease was primarily due to lower bonus
expense in the current year resulting from lower earnings.
Other Non-Operating
Other income and deductions, net of taxes, increased $4.8 million for the
period to $7.4 million primarily due to charges in 2001 that did not recur in
2002. On a pre-tax basis in 2001, the Company recognized charges of $8.3 million
to write-off certain permanently impaired Avistar investments and costs of $1.0
million related to the Company's terminated acquisition of Western Resources'
electric utility operations, partially offset by $3.4 million of equity income
from a passive investment. The current year also had a decrease in investment
income of $0.3 million on the PVNGS decommissioning trust assets.
The Company's consolidated income tax expense was $14.2 million for the
three months ended March 31, 2002, compared to $42.8 million for the three
months ended March 31, 2001. The impact of lower earnings in 2002 contributed to
the difference. The Company's effective income tax rates for the three months
ended March 31, 2002 and 2001 were 36.28% and 40.26%, respectively. Included in
the Company's 2001 taxable income were certain non-deductible costs related to
the Company's acquisition of Western Resources' electric utility operations.
Excluding these costs, the Company's effective tax rate was 39.0% in 2001. The
decrease in the effective rate was primarily due to adjustments to the Company's
prior year tax returns for certain research and development credits.
36
FUTURE EXPECTATIONS
On April 24, 2002, the Company announced that it was revising its 2002
earnings expectations. The Company now expects full year 2002 earnings to be in
the range of $2.60 to $2.85. This earnings guidance is affected by three primary
factors. Average wholesale prices in the West are expected to be lower than
previously projected by the Company. In addition, the Company expects liquidity
to return to the wholesale marketplace at lower levels than previously
anticipated. Accordingly, lower liquidity in the wholesale market will affect
the Company's ability to buy and resell power leading to a lower ratio of total
sales to generation. Finally, the Company revised its outlook on forward spark
spreads, the difference between the cost of gas generation and the wholesale
price of electricity. Because the Company's current gas generation assets are
essentially peaking resources, earnings contribution from these resources occurs
only when the spark spread exceeds approximately $15 per MWh. The Company is now
assuming spark spreads to remain below the level necessary to justify use of its
gas generation. Consequently, the revised earnings guidance presumes that there
will be no earnings contributions from the Company's gas peaking resources. The
calculation of future expected earnings is also subject to numerous variables,
including on and off-peak wholesale demand, retail load needs, generating
resource availability, the current position of the Company's trading portfolio
and general economic conditions.
While the Company manages the short-term impacts of the current wholesale
market, it remains committed to the implementation of its strategic plan. The
Company is proceeding with the construction of two new generating plants in
southern New Mexico. Because transmission constraints make it difficult to
import power into that area, the Company believes these new plants are a sound
long-term investment. The Company is currently looking beyond New Mexico for
additional resources, and it is looking to buy existing assets rather than
building, because the current downturn in power prices has made assets available
at more attractive prices.
As a result of the reduced pricing environment, many generators have
announced the cancellation of previously planned projects. The Company expects
that forward prices will again move upward in future periods as a result of
under building and overall increased demand for electricity. As the Company adds
new generation resources, it is expected that earnings will trend upwards as
sales volumes grow. This earnings growth is expected to be in high single digits
over the long-term.
This discussion of future expectations is forward looking information
within the meaning of Section 21E of the Securities Exchange Act of 1934. The
achievement of expected results is dependent upon the assumptions described in
the preceding discussion, and is qualified in its entirety by the Private
Securities Litigation Reform Act of 1995 disclosure - (see "Disclosure Regarding
Forward Looking Statements" below) - and the factors described within the
disclosure that could cause the Company's actual financial results to differ
materially from the expected results enumerated above.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2002, the Company had cash and short-term investments of
$178.7 million compared to $176.8 million in cash, short-term and long-term
investments at December 31, 2001. Certain long-term investments have been
reclassified as short-term to reflect the Company's liquidity needs to fund
certain construction projects in 2002.
37
Cash provided from operating activities in the three months ended March
31, 2002 was $15.4 million compared to cash provided by operating activities of
$109.5 million for the three months ended March 31, 2001. The Company did not
make its first quarter 2001 estimated federal income tax payment until January
2002 because of an extension granted by the IRS to taxpayers in several counties
in New Mexico as a result of wildfires in 2000. This out-of-period income tax
payment reduced operating cash flows below normal levels.
Cash used for investing activities was $62.5 million in 2002 compared to
$47.2 million in 2001. Cash used for investing activities includes construction
expenditures for new generating plants of $48.1. The decline in expenditures
reflects the acquisition of certain transmission assets and other related
investing activities of $13.9 which did not recur in 2002.
Cash generated by financing activities was $47.7 million in 2002 compared
to $8.7 million of cash used in 2001. Financing activities in 2002 were
primarily short-term borrowings for liquidity reasons, partially offset by cash
payments for dividend requirements. The use of cash in 2001 primarily reflects
cash payments for dividend requirements.
Pension and Other Postretirement Benefits
In 2001, the investment market experienced significant declines due to
various reasons. As a result, the Company adjusted the expected rate of return
on its pension and other postretirement benefit plans assets. In 2002, the
Company expects its rate of return on plan assets will return to historic
levels. For the three months ended March 31, 2002, the Company's net periodic
benefit cost assumed a 7.75% rate of return as compared to 9.00% in the prior
year. In addition, in January 2002, the Company made an aggregate contribution
of $23.5 million to fund the pension and other postretirement benefit plans. The
effect of this contribution was to reduce the impact that the actual investment
losses will have on the Company's future net periodic benefit cost. The effect
of the change in expected rate of return and the additional cash contribution
was a decrease in pension and other post retirement benefits expense of $3.0
million for the quarter ended March 31, 2002.
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 for 2002 are
$409 million and projections for construction expenditures for 2002 are $391
million. For 2002-2006 projections, total capital requirements are $1.9 billion
and construction expenditures are $1.8 billion, including the combustion
turbines discussed below. These estimates are under continuing review and
subject to on-going adjustment.
38
PNM has committed to purchase five combustion turbines for a total cost
of $151.3 million. The turbines are for planned power generation plants with an
estimated cost of construction of approximately $370 million. PNM has expended
$160 million as of March 31, 2002 of which $117.2 million was for equipment
purchases. In November 2001, PNM broke ground to build Afton Generating Station,
a 135 MW single cycle gas turbine plant in Southern New Mexico. In February
2002, PNM broke ground to build Lordsburg Generating Station ("Lordsburg"), an
80 MW natural gas fired generating plant in Southern New Mexico. In January of
2002, the Lordsburg City Council approved the issuance of industrial revenue
bonds for Lordsburg and on February 28, 2002, passed a bond ordinance. Contracts
have not been finalized on the remaining planned construction. These plants are
part of the Company's ongoing competitive strategy of increasing generation
capacity over time. This construction is not anticipated to be added to rate
base.
The Company's construction expenditures for 2001 were entirely funded
through cash generated from operations. In the first quarter of 2002, the
Company utilized its liquidity arrangements to cover the difference between the
timing of its cash flows and its construction commitments. To meet its capital
needs for its planned expansion of its generation capabilities, the Company
expects that it will have to access the capital markets. Otherwise, the Company
anticipates that internal cash generation and current debt capacity will be
sufficient to meet all its other capital requirements for the years 2002 through
2006. 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 May 1, 2002, PNM had $190 million of available liquidity arrangements,
consisting of $150 million from an unsecured revolving credit facility ("Credit
Facility"), $20 million in local lines of credit and $20 million from a
reciprocal borrowing agreement with the Holding Company. The Credit Facility
will expire in March 2003. There were $106.3 million in borrowings as of May 1,
2002. In addition, the Holding Company has a $20 million reciprocal borrowing
agreement with PNM and $25 million in local lines of credit.
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.
PNM's credit outlook is considered positive by Moody's Investor Services
("Moody's") and Fitch Ratings ("Fitch") and stable by Standard and Poors
("S&P"). Previously, in connection with PNM's announcement of its agreement to
acquire Western Resources' electric utility operations, S&P, Moody's and Fitch
placed PNM's securities ratings on negative credit watch pending review of the
transaction. As a result of events which led the Company to conclude the
acquisition could not be accomplished, ultimately leading the Company to
terminate the transaction in January 2002, S&P, Moody's and Fitch removed the
Company from negative credit watch. The Company is committed to maintaining its
investment grade. S&P currently rates PNM's senior unsecured notes ("SUNs") and
its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its
preferred stock "BB". Moody's rates PNM's SUNs and senior unsecured pollution
control revenue bonds "Baa3"; and preferred stock "Ba1". The EIP senior secured
debt is also rated "Ba1". Fitch rates PNM's SUNs and senior unsecured pollution
control revenue bonds "BBB-," PNM's EIP lease obligation "BB+" and PNM's
39
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.
Long-term Obligations and Commitments
The following table shows PNM's long-term debt and operating leases as of
March 31, 2002. As of March 31, 2002, the Holding Company has no long-term
obligations except those acquired through consolidation with PNM.
Payments Due
-----------------------------------------------------------------------
(In thousands)
Less than
Contractual 1 year 2-3 years 4-5 years After 5
Obligations Total years
------------- ----------- ----------- ----------- -------------
Long-Term Debt.................. $953,898 $ - $ - $268,420 $685,478
Operating Leases................ 524,930 32,333 66,592 70,560 355,445
------------- ----------- ----------- ----------- -------------
Total Contractual Cash
Obligations.................. $1,478,828 $32,333 $66,592 $338,980 $1,040,923
============= =========== =========== =========== =============
PNM leases interests in Units 1 and 2 of PVNGS, certain transmission
facilities, office buildings and other equipment under operating leases. The
lease expense for PVNGS is $66.3 million per year over base lease terms expiring
in 2015 and 2016. In 1998, PNM established PVNGS Capital Trust ("Capital Trust")
for the purpose of acquiring all the debt underlying the PVNGS leases. PNM
consolidates Capital Trust in its consolidated financial statements. The
purchase was funded with the proceeds from the issuance of $435 million of SUNs,
which were loaned to Capital Trust. Capital Trust then acquired and now holds
the debt component of the PVNGS leases. For legal and regulatory reasons, the
PVNGS lease payment continues to be recorded and paid gross with the debt
component of the payment returned to PNM via Capital Trust. As a result, the net
cash outflows for the PVNGS lease payment were $12.4 million as of 2002. The
table above reflects the net lease payment.
PNM's other significant operating lease obligations include the Eastern
Interconnect Project ("EIP"), a transmission line with annual lease payments of
$7.3 million, and a power purchase agreement for the entire output of Delta
Person Generating Station ("Delta"), a gas-fired generating plant in
Albuquerque, New Mexico with imputed annual lease payments of $6.0 million.
The Company's off-balance sheet obligations are limited to PNM's
operating leases and certain financial instruments related to the purchase and
sale of energy (see below). The present value of PNM's operating lease
obligations for PVNGS Units 1 and 2, EIP and the Delta PPA was $225 million as
of December 31, 2001.
PNM has entered various long-term power purchase agreements obligating it
to make aggregate fixed payments of $30.3 million plus the cost of production
and a return. These contracts expire December 2006 through July 2010. In
addition, PNM is obligated to sell electricity for $158.1 million in fixed
40
payments plus the cost of production and a return. These contracts expire
December 2003 through June 2010. PNM's trading portfolio as of March 31, 2002
included open contract positions to buy $63.0 million of electricity and to sell
$31.2 million of electricity. In addition, PNM had open contract positions
classified as normal sales of electricity under the derivative accounting rules
of $16.3 million and normal purchases of electricity of $42.9 million.
PNM has a coal supply contract for the needs of San Juan Generating
Station ("SJGS") until 2017. The contract contemplates the delivery of
approximately 103 million tons of coal during its remaining term. The pricing is
based on the cost of extraction plus a margin.
PNM contracts for the purchase of gas to serve its jurisdictional
customers. These contracts are short-term in nature supplying the gas needs for
the current heating season and the following off-season months. The price of gas
is a pass-through, whereby the Company recovers 100% of its cost of gas.
Contingent Provisions of Certain Obligations
The Holding Company and PNM have a number of debt obligations and other
contractual commitments that contain contingent provisions. Some of these, if
triggered, could affect the liquidity of the Company. The Holding Company and/or
PNM could be required to provide security, immediately pay outstanding
obligations or be prevented from drawing on unused capacity under certain credit
agreements, if the contingent requirements were to be triggered. The most
significant consequences resulting from these contingent requirements are
detailed in the discussion below.
PNM's master purchase agreement for the procurement of gas for its
jurisdictional customers contains a contingent requirement that could require
PNM to provide security for its gas purchase obligations if the seller were to
reasonably believe that PNM was unable to fulfill its payment obligations under
the agreement.
The master agreement for the sale of electricity in the Western System
Power Pool ("WSPP") contains a contingent requirement that could require PNM to
provide security if its' debt were to fall below the investment grade rating.
The WSPP agreement also contains a contingent requirement, commonly called a
material adverse change ("MAC") provision, which could require PNM to provide
security if a material adverse change in its financial condition or operations
were to occur.
PNM's committed Credit Facility contains a MAC provision which if
triggered could prevent PNM from drawing on its unused capacity under the Credit
Facility. In addition, the Credit Facility contains a contingent requirement
that requires PNM to maintain a debt-to-capital ratio of less than 70%. If PNM's
debt-to-capital ratio were to exceed 70%, PNM could be required to repay all
borrowings under the Credit Facility, be prevented from drawing on the unused
capacity under the Credit Facility, and be required to provide security for all
outstanding letters of credit issued under the Credit Facility. At March 31,
2002, the Company had $8.5 million of letters of credit outstanding.
If a contingent requirement were to be triggered under the Credit
Facility resulting in an acceleration of the outstanding loans under the Credit
Facility, a cross-default provision in the PVNGS leases could occur if the
accelerated amount is not paid. If a cross-default provision is triggered, the
lessors have the ability to accelerate their rights under the leases, including
acceleration of all future lease payments.
41
Planned Financing Activities
PNM has $268.4 million of long-term debt that matures in August 2005. All
other long-term debt matures in 2016 or later. The Company could enter into
other 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 PNM'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 PNM's financial instruments would ultimately limit the amount of SUNs PNM
would issue.
PNM currently has $182.0 million of tax-exempt bonds outstanding that are
callable at a premium in December 2002 and August 2003. PNM intends to refinance
these bonds assuming the interest rate of the refinancing does not exceed the
current interest rate of the bonds and has hedged the entire planned
refinancing. In order to take advantage of current low interest rates, PNM
entered into two forward starting interest rate swaps in November and December
2001 and three additional contracts during the first quarter of 2002. PNM
designated these swaps as cash flow hedges. The hedged risks associated with
these instruments are the changes in cash flows related to general moves in
interest rates expected for the refinancing. The swaps effectively cap the
interest rate on the refinancing to 4.9% plus an adjustment for PNM's and the
industry's credit rating. PNM's assessment of hedge effectiveness is based on
changes in the hedge interest rates. The derivative accounting rules, as
amended, provide 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
transactions affect earnings. Any hedge ineffectiveness is required to be
presented in current earnings. There was no material hedge ineffectiveness in
the three months ended March 31, 2002.
A forward starting swap does not require any upfront premium and captures
changes in the corporate credit component of an investment grade company's
interest rate as well as the underlying Treasury benchmark. The five forward
interest rate starting swaps have termination dates and notional amounts as
follows: one with a termination date of September 17, 2002 for a notional amount
of $46.0 million and four with a termination date of May 15, 2003 for a combined
notional amount of $136.0 million. There were no fees on the transaction, as
they are imbedded in the rates, and the transaction is cash settled on the
mandatory unwind date (strike date), corresponding to the refinancing date of
the underlying debt. The settlement will be capitalized as a cost of issuance
and amortized over the life of the debt as a yield adjustment.
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 ability of the Company's subsidiaries to pay
dividends. Currently, PNM is the Company's primary source of dividends. As part
of the order approving the formation of the holding company, the PRC placed
certain restrictions on the ability of PNM to pay dividends to its parent.
42
The PRC order imposed the following conditions regarding dividends paid
by PNM to the holding company: PNM cannot pay dividends which cause its debt
rating to go below investment grade; and PNM cannot pay dividends in any year,
as determined on a rolling four quarter basis, in excess of net earnings without
prior PRC approval. Additionally, PNM has various financial covenants which
limit the transfer of assets, through dividends or other means.
In addition, the ability of the Company to declare dividends is dependent
upon the extent to which cash flows will support dividends, the availability of
retained earnings, its financial circumstances and performance, the PRC's
decisions in various regulatory cases currently pending and which may be
docketed in the future, the effect of deregulating generation markets and market
economic conditions generally. 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.
Consistent with the PRC's holding company order, PNM paid dividends of
$127.0 million to the Company on December 31, 2001. On March 4, 2002, the PNM
Board of Directors declared an additional dividend of approximately $5.5
million, which was paid March 19, 2002.
On February 19, 2002, the Company's Board of Directors approved a 10
percent increase in the common stock dividend. The increase raises the quarterly
dividend to $0.22 per share, for an indicated annual dividend of $0.88 per
share. The Company's Board of Directors approved a policy for future dividend
increases in the range of 8 to 10 percent annually, targeting a payout of
between 50 to 60 percent of regulated earnings. The Company believes that this
target is consistent with the Company's expectation of future operating cash
flows and the cash needs of its planned increase in generating capacity.
Capital Structure
The Company's capitalization, including current maturities of long-term
debt, at March 31, 2002 and December 31, 2001 is shown below:
March 31, December 31,
2002 2001
------------- --------------
Common Equity......................... 51.3% 50.8%
Preferred Stock....................... 0.6 0.6
Long-term Debt........................ 48.1 48.6
------------- --------------
Total Capitalization*.............. 100.0% 100.0%
============= ==============
*Total capitalization does not include as debt the present value of
PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and
the Delta PPA which was $225 million as of March 31, 2002 and $225
million as of December 31, 2001.
43
OTHER ISSUES FACING THE COMPANY
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. The Company is unable to predict the form its
further restructuring will take under the delayed implementation of customer
choice. In addition, 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.
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.
On December 31, 2001, the Company implemented the holding company
structure 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 PNM,
Avistar and other inactive unregulated subsidiaries. This was effected through
the share exchange between PNM shareholders and the holding company, PNM
Resources. Avistar and most of the inactive unregulated subsidiaries became
wholly-owned subsidiaries of the holding company in January 2002. The transfer
of certain corporate related assets to the holding company also occurred in
January 2002. There are no current plans to provide the holding company with
significant debt financing.
The 2002 session of the New Mexico Legislature resulted in enactment of
tax measures favorable to the construction of merchant generating plants and
plants fueled by renewable resources. The new laws provide authority for all
local governments in the state to issue industrial revenue bonds for merchant
generating plants smaller than 300 MW. The bonds provide exemptions from
property taxes. Also enacted into law was a 5% investment tax credit for
merchant generating plants smaller than 300 MW; tax credits for qualified
generators using renewable resources; and an exemption from gross receipts tax
for the cost of certain wind generation equipment.
There is a growing concern in New Mexico about the use of water for
merchant power plants, due to the increased activity in building these plants in
the state, which has an arid climate. The availability of sufficient water
supplies to meet all the needs of the state, including growth, is a major issue.
It is expected that the Legislature will appoint an interim committee to study
the impact of power plants on the state's water and other natural resources,
with a report to be issued for the 2003 session. In building the Afton and
Lordsburg plants, which are much smaller than other merchant plants under
construction or planned by other generating companies, the Company has secured
sufficient water rights.
44
On April 25, 2002, by a vote of 88-11, the U.S. Senate passed amendments
to HR 4, the "Energy Policy Act of 2002". The Senate version contains provisions
directly applicable to the electric industry, many of which were not contained
in the House version of HR 4. As adopted by the Senate, HR 4 contains provisions
revising FERC authority over utility mergers; provides direction to the FERC
regarding the use of market-based rates; provides for possible refunds dating
from the date of a complaint rather than the current 60 day waiting period;
provides for a reliability organization to establish standards subject to the
FERC oversight; requires the FERC to establish an electronic information system
about wholesales sales and transmission; extends FERC jurisdiction over large
municipal utilities, cooperatives and power marketing agencies; requires access
to transmission for intermittent generators that are exclusively solar or wind;
repeals Public Utility Holding Company Act ("PUHCA"); provides for federal and
state access to holding company records; conditionally repeals the Public
Utility Regulatory Policy Act ("PURPA") if qualifying facilities have access to
independent, day-ahead and real-time auction based markets; requires states to
consider adopting standards for real time pricing, time of use metering and net
metering; authorizes the Federal Trade Commission ("FTC") to establish consumer
protection rules; establishes consumer advocates in the Department of Justice
("DOJ"); requires federal agencies to attempt to purchase a percentage of
electricity from renewable sources, starting at 3% increasing to 7.5%;
establishes renewable portfolio standard for investor owned utilities that
increases to 10% by 2020; establishes a voluntary registry for reporting
greenhouse gas emissions and emission reductions (which could become mandatory
for reporting emissions within 5 years); reforms nuclear decommissioning tax
provisions; provides tax relief for sale of transmission assets to an
independent transmission company; extends protections against liability for
nuclear accidents under Price-Anderson Act. The differences in the two versions
of HR 4 will be the subject of conference committee discussions later this year.
The Company is unable to predict what form energy legislation will take if
agreement is reached between the House and the Senate, if energy legislation
will be passed or if it will be signed by the President if passed. Included in
the debate over energy legislation are drilling in the Arctic National Wildlife
Refuge and automobile fuel efficiency requirements.
The Company along with other Southwest transmission owners formed
WestConnect RTO, LLC ("WestConnect") a for-profit transmission company and made
a filing on October 16, 2001 with the FERC. WestConnect is the only remaining
Regional Transmission Organization ("RTO") still proposing a transmission asset
owning company form of governance. However, WestConnect allows for, but does not
require a member to transfer its transmission assets. WestConnect is awaiting a
FERC order on its formation.
The FERC has initiated a separate Notice of Proposed Rulemaking that
would require implementation of new Open Access Transmission Tariffs by RTOs and
by public utilities that own, operate, or control interstate transmission
facilities. The new tariffs would adopt provisions to implement new transmission
services and a standardized wholesale market design. The new functions would be
implemented by an independent entity, which could be an RTO, that would perform
services under the standard market design under rules applicable to all
transmission customers. The Company has made comments on the Standard Market
Design Staff papers along with the other WestConnect companies and will continue
to participate in the rulemaking process. The Company is also following FERC
rulemakings on Standards of Conduct and Standardizing Generation Interconnection
Agreements and Procedures.
45
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.
These 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 Nuclear Regulatory
Commission 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 seek 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 $143 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 assets continue to be classified as regulatory assets, although the
Company has discontinued the use of accounting for rate regulated activities.
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 the costs are fully recoverable. The Company
believes that any remaining portion of the regulatory assets will be fully
recovered in future rates, including through a 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 time of separation. If regulatory orders do
not provide for a reasonable recovery, the Company is prepared to vigorously
pursue judicial remedies. The PRC will make a determination and quantification
of stranded cost recovery prior to implementation of restructuring. The
determination may have an impact on the recoverability of the related assets and
may have a material effect on the future financial results and position of the
Company.
46
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 may seek to recover
transition costs already incurred in future rate cases that may occur prior to
open access. The Company is unable to predict the amount of transition costs it
may incur. To date, the Company has capitalized $156.4 million of expenditures
that meet the Restructuring Act's definition of transition 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. These costs 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. Depending on the amount of non-recoverable transition costs,
if any, the resulting charge to earnings may have a material effect on the
future financial results and position of the Company.
Nuclear Regulatory Commission 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.
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. The
results of the 1998 triannual decommissioning cost study indicated that PNM's
share of the PVNGS decommissioning costs excluding spent fuel disposal will be
approximately $181 million (in 1998 dollars). 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.
47
MERCHANT PLANT FILING
Senate Bill ("SB") 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 regulatory requirements contained in 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 services and merchant plants will be conducted. The Company has filed
a pleading addressing these issues and testimony in response to interested
parties' requests. The PRC established a schedule for the filing of staff and
intervenor testimony and for the Company's rebuttal testimony, culminating in a
hearing initially scheduled for June 10, 2002, although that procedural schedule
was recently vacated and the hearing has not yet been rescheduled.
In November 2001, the Company began settlement negotiations with the
PRC's utility staff and intervenors related to these PRC proceedings in order to
resolve a number of matters. In addition to the issues being examined in the
Company's merchant plant filing, discussions have included the future framework
for restructuring the electric industry in New Mexico under the Restructuring
Act, and a future retail electric rate path. The negotiations include the
potential implementation and effective date of rates that would replace those
approved under the rate freeze stipulation that remains in effect until January
1, 2003.
The Company is currently unable to predict the impact these proceedings
may have on its plans to expand its generating capacity and other operations.
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 during the first half of the year. 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, presented
and continues to present significant risk to companies selling power into this
marketplace.
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,
conservation measures and new generation have or are expected 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 than the levels seen during the first half of
2001.
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
48
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 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, Southern California Edison Company ("SCE") and Pacific Gas and
Electric Co. ("PG&E"), were unable to fully recover their wholesale power costs
from their retail customers. As a result, both utilities experienced severe
liquidity constraints. PG&E eventually sought bankruptcy protection.
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 these markets be
capped at $150 per MWh unless the seller could demonstrate that its costs
exceeded 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
for overcharges calculated on the basis of a formula that sanctioned wholesale
prices considerably in excess of the $150 per 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 per MWh soft cap
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 by the end of the third quarter
and remained low since then. 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 were due resulting from wholesale sales into the
Pacific Northwest. The Pacific Northwest matter was heard by an administrative
law judge whose recommended decision declined to order refunds resulting from
49
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 and a recommended decision is not anticipated until the
second half of 2002. 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 FERC order.
The FERC has also, partially in response to the Enron bankruptcy filing
and to allegations that Enron may have engaged in market manipulation of
portions of the Western United States wholesale power market, initiated a market
manipulation investigation. In connection with that investigation all FERC
jurisdictional and non-jurisdictional sellers into western electric and gas
markets have been required to submit data regarding short-term transactions in
2000-2001. The Company made its data submission on April 2, 2002. Subsequently,
in the first week of May 2002, new Enron documents came to light that raised
additional concerns about Enron's trading practices. In light of these new
revelations, on May 8, 2002, the FERC issued an order in the pending
investigation requiring sellers to respond to detailed questions about whether
they have engaged in trading practices similar to those practiced by Enron.
Responses are due to be filed by May 22, 2002.
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 Cal PX and ISO, defaulted
on payments due the Cal PX for power purchased from the Cal 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 proceedings. Total
amounts due from the Cal PX or Cal ISO for power sold to them in 2000 and 2001
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 the
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 issued a ruling on these complaints
eliminating the "charge-back" mechanism.
Additionally, in March 2002, the California Attorney General filed a
complaint at the FERC against numerous sellers regarding prices for sales into
the Cal ISO and Cal PX and to the California Department of Water Resources ("Cal
DWR"). The Company was among the sellers identified in this complaint and the
Company filed its answer and motion to intervene on April 2, 2002. In its
answer, the Company defended its pricing and challenged the theory of liability
underlying the California Attorney General's complaint. As addressed below, the
California Attorney General has also threatened litigation in state court in
California based on similar allegations.
With the demise of the Cal PX in February 2001, the 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 this funding would be replaced with the issuance of
revenue bonds by the state. 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.
50
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 $3.5 million for anticipated losses to reflect management's estimate
of the increased market and credit risk in the wholesale power market and its
impact on 2001 revenues. No additional reserves were made for the three months
ended March 31, 2002. Based on information available at March 31, 2002, the
Company believes the total allowance for anticipated losses, currently
established at $12.0 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. Other related investigations have been commenced by other federal and
state governmental bodies. The California Attorney General has filed several
lawsuits in California state court against certain power marketers for alleged
unfair trade practices involving alleged overcharges for electricity. By letter
dated April 9, 2002, the California Attorney General notified the Company of his
intent to file a complaint in California state court against the Company by the
middle of April 2002 concerning the Company's alleged failure to file rates for
wholesale electricity sold in California and for allegedly charging unjust and
unreasonable rates in the California markets. For each alleged violation, the
letter indicates an intent to seek penalties of $2,500 per violation. The letter
invited the Company to contact the California Attorney General's office before
the complaint is filed, and the Company has met with the California Attorney
General's office to begin a dialogue. To date, suit has not been filed by the
Attorney General and the Company cannot predict the ultimate outcome of this
matter.
Several class action lawsuits have been filed in California state courts
against electric generators and marketers, alleging that the defendants violated
the law by manipulating the market to grossly inflate electricity prices. Named
defendants in these lawsuits include Duke Energy ("Duke") and related entities
along with other named sellers into the California market and numerous other
"unidentified defendants." These lawsuits have been consolidated for hearing in
51
state court in San Diego. On May 3, 2002, the Duke defendants in the foregoing
state court litigation served on PNM a cross-claim. Duke also cross-claimed
against many of the other sellers into California. Duke asked for declaratory
relief and for indemnification for any damages that might ultimately be imposed
on Duke. PNM's answer will (unless an extension of time is obtained) be due in
early June, and PNM is in the process of reviewing the cross-complaint. PNM
cannot predict the ultimate outcome of this matter.
TERMINATION OF WESTERN RESOURCES TRANSACTION
On November 9, 2000, PNM and Western Resources announced that both
companies' Boards of Directors approved an agreement under which PNM would
acquire the Western Resources electric utility operations in a tax-free,
stock-for-stock transaction. The agreement required that Western Resources
split-off its non-utility businesses to its shareholders prior to closing.
In July 2001, the KCC issued two orders. The first order declared the
split-off required by the agreement to be unlawful as designed, with or without
a merger. The second order decreased rates for Western Resources, despite a
request for a $151 million increase. After rehearing the KCC established the
rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on
Reconsideration reaffirming its decision that the split-off as designed in the
agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001, in New York state court
seeking declarations that the transaction could not be accomplished as 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 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.
On November 19, 2001, Western Resources filed a complaint against the
Company in New York state court alleging breach of contract and breach of
implied covenant of good faith and fair dealing. Western Resources alleged that
the Company brought about the KCC orders, failed to assist in efforts to reverse
the KCC orders, refused to renegotiate within the terms of the agreement,
interfered with Western Resources' efforts to satisfy the terms of the
agreement, and effected an unauthorized de facto termination of the agreement by
filing its complaint. Western Resources alleges damages in excess of $650
million. The Company believes that the complaint filed by Western Resources is
without merit and intends to vigorously defend itself against the complaint. The
Company also intends to vigorously pursue its own complaint.
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect.
52
On February 5, 2002, the District Court for Shawnee County, Kansas,
dismissed without prejudice Western Resources' petition for judicial review of
the KCC's split-off orders. The Court ruled that by filing a new financial plan
in compliance with the orders, Western Resources accepted certain portions of
the orders thereby creating a situation where further administrative action
became necessary. As a result, the Court concluded that the matter was not ripe
for judicial review and remanded the case to the KCC.
On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate
order. On April 8, 2002, Western Resources filed with the Kansas Supreme Court a
Petition for Review of the Court of Appeals decision.
On May 2, 2002, the New York court issued an order denying Western
Resources' motion for stay or dismissal of the Company's complaint. At the same
time, the court granted the Company's motion to dismiss Western Resources'
complaint, without prejudice. As a result, the Company has been determined to be
the plaintiff in the litigation but Western Resources will be allowed, when it
files its answer, to reassert its claims against the Company as affirmative
defenses or counterclaims, if it so chooses.
On May 10, 2002, the Company filed an Amended Complaint seeking
unspecified damages from Western Resources for numerous breaches of contract
related to the determination that the split-off required by the agreement was
unlawful and required prior approval by the KCC. The Company also seeks
unspecified damages for additional breaches of contract because: Western
Resources failed to provide the Company with the opportunity to review and
comment on information related to the transaction provided by Western Resources
to third parties; Western Resources failed to obtain the Company's consent to
amend existing employee compensation and benefits plans or create new ones; and
Western Resources filed for approval of an alternative debt reduction plan that
represents the abandonment of the split-off required by the agreement. In
addition the Company seeks numerous declarations from the court, including that
the Company was not obligated to perform because conditions regarding
performance were not satisfied; the Company did not breach when it terminated
the agreement; and the rate case order constitutes a material adverse effect
under the terms of the agreement.
The Company is currently unable to predict the outcome of its litigation
with Western Resources.
Effects of Certain Events on Future Revenues
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").
In 2001, FERC issued a "proposed" order directing the Company to provide
transmission service, but left the terms of service to be negotiated by the
parties and subject to final FERC review and determination. In January 2002, the
parties submitted a settlement agreement resolving most of the issues relating
to the rates, terms and conditions of service. The settlement agreement reserves
the Company's rights to seek rehearing and judicial review of any final order
and to present other legal claims. On April 12, 2002, the FERC approved the
settlement, and on April 29, 2002, the FERC issued its Final Order directing the
Company to provide the service. The Company is evaluating its legal options in
relation to the final order. A related PRC proceeding has been stayed, pending
the outcome of the FERC case.
Should DOE on behalf of KAFB choose to use WAPA for purchase and
transmission services instead of the current retail sale that the Company makes
to DOE, the effect of the FERC's proposed order to provide transmission service,
depends upon 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
believes that the impact will be immaterial based on the facts above.
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
53
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
litigation. No complaint has been filed against the Company by the EPA, 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. 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.
Threatened Citizen Suit Under the Clean Air Act
By letter dated January 9, 2002, counsel for the Grand Canyon Trust and
Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a
so-called "citizen suit" under the Clean Air Act, alleging that the Company and
co-owners of the SJGS violated the Clean Air Act, and the implementing federal
and state regulations, at SJGS. The notice indicates that penalties and
injunctive relief may be sought. Under the Clean Air Act, GCT must wait at least
60 days after affording the Company notice (i.e., until March 9, 2002) before
filing a lawsuit. The allegations contained in GCT's notice of intent to sue
fall into three categories. First, GCT contends that the plant has violated, and
is currently in violation of, the federal NSPS at all four units at SJGS.
Second, GCT argues that the plant has violated, and is currently in violation
of, the federal PSD rules, as well as the corresponding provisions of the New
Mexico Administrative Code, at all four units. Third, GCT alleges that the plant
has "regularly violated" the 20% opacity limit contained in SJGS's operating
permit and set forth in federal and state regulations at Units 1, 3 and 4. The
Company is currently investigating the allegations contained in the notice of
intent to sue. Based on its investigation to date, the Company firmly believes
that the allegations are without merit. By letter to GCT's counsel dated
February 22, 2002, the Company vigorously disputed the allegations and affirmed
its compliance with the laws in question. The Company adheres to high
environmental standards as evidenced by its International Standards Organization
ratings. In that letter, the Company also stated that the GCT had failed to
provide sufficient information to permit full examination of the allegations. If
a lawsuit is filed by GCT, as threatened, the Company will respond on behalf of
the co-owners and vigorously defend in the litigation. The Company is, however,
unable to predict the ultimate outcome of the matter.
54
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 Company's investigation indicates that the
leak was an isolated incident likely caused by a combination of corrosion and
increased pressure. The Company also is cooperating with an investigation of the
incident by the PRC's Pipeline Safety Bureau which issued its report on March
18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the
New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the
Company by the injured persons along with 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 as a result of the Pipeline Safety Bureau's investigation.
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
Arizona Public Service Company ("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 and
cannot estimate with any certainty the potential impact on the Company's
operations.
LANDOWNER ENVIRONMENTAL CLAIMS
In March 2002, a lawsuit was filed by a landowner owning property in the
vicinity of the San Juan Generating Station, Raymond G. Hunt, against the
Company and the owner of the coal mine that supplies coal to the plant. The
lawsuit has not, however, been served on the defendants pending the outcome of
scheduled discussions between the parties. The complaint seeks $20 million in
damages, plus pre-judgment interest and punitive damages, based on allegations
related to the alleged discharge of pollutants into an arroyo near the plant,
including damage to the plaintiff's livestock. A jury trial has been demanded.
The Company is unable to predict the outcome of this matter.
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
55
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 all forward-looking statements are based upon current
expectations and are subject to risk and uncertainties. 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,
the outcome of litigation relating to the Company's terminated transaction with
Western Resources, the performance of generating units and transmission system,
the success of the Company's planned generation expansion 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 PRC 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 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 and wholesale power markets
in the West, could cause the Company's results or outcomes to differ materially
from those indicated by such forward-looking statements in this filing.
56
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, changes in interest rates
and, historically, 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 the Company's financial instruments is set forth in "Critical
Accounting Policies" section of Management's Discussion of Results of Operations
and Financial Condition and the Financial Instruments note in the Notes to the
Consolidated Financial Statements and incorporated by reference. The following
additional information is provided.
Risk Management
The Company controls the scope of its various forms of risk through a
comprehensive set of policies and procedures and oversight by senior level
management and the Board of Directors. The Company's Finance Committee of the
Board of Directors sets the risk limit parameters. An internal risk management
committee ("RMC"), comprised of corporate and business segment officers,
oversees all of the activities, which include commodity price, credit, equity,
interest rate and business risks. The RMC has oversight for the ongoing
evaluation of the adequacy of the risk control organization and policies. The
Company has a risk control organization, headed by the Director of Financial
Risk Management ("Risk Manager"), which is assigned responsibility for
establishing and enforcing the policies, procedures and limits and evaluating
the risks inherent in proposed transactions, on an enterprise-wide basis.
The RMC's responsibilities specifically include: establishment of a
general policy regarding risk exposure levels and activities in each of the
business units; recommendation of the types of instruments permitted for
trading; authority to establish a general policy regarding counterparty exposure
and limits; authorization and delegation of trading transaction limits for
trading activities; review and approval of controls and procedures for the
trading activities; review and approval of models and assumptions used to
calculate mark-to-market and risk exposure; authority to approve and open
brokerage and counterparty accounts for derivative trading; review for trading
and risk activities; and quarterly reporting to the Finance Committee and the
Board of Directors on these activities.
The RMC also proposes Value at Risk ("VAR") limits to the Finance
Committee. The Finance Committee ultimately sets the aggregate VAR limit.
It is the responsibility of each business unit to create its own control
and procedures policy for trading within the parameters established by the
Finance Committee. The RMC reviews and approves these policies, which are
created with the assistance of the Chief Accounting Officer, Director of
Internal Audit and the Risk Manager. Each business units' policies address the
following controls: authorized risk exposure limits; authorized trading
instruments and markets; authorized traders; policies on segregation of duties;
policies on marking to market; responsibilities for trade capture; confirmation
procedures; responsibilities for reporting results; statement on the role of
derivatives trading; and limits on individual transaction size (nominal value)
for traders.
57
To the extent an open position exists, fluctuating commodity prices can
impact financial results and financial position, either favorably or
unfavorably. As a result, the Company cannot predict with precision the impact
that its risk management decisions may have on its businesses, operating results
or financial position.
Commodity Risk
Trading and marketing operations often involve market risks associated
with managing energy commodities and establishing open positions in the energy
markets, primarily on a short-term basis. These risks fall into three different
categories: price and volume volatility, credit risk of trading counterparties
and adequacy of the control environment for trading. The company routinely
enters into forward contracts and options to hedge purchase and sale
commitments, fuel requirements and to minimize the risk of market fluctuations
on the Generation and Trading Operations.
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 assesses the risk of these derivatives using the VAR method,
in order to maintain the Company's total exposure within management-prescribed
limits. The Company utilizes the variance/covariance model of VAR, which is a
probabilistic model that measures the risk of loss to earnings in market
sensitive instruments. The variance/covariance model relies on statistical
relationships to analyze how changes in different markets can affect a portfolio
of instruments with different characteristics and market exposure. VAR models
are relatively sophisticated; however, the quantitative risk information is
limited by the parameters established in creating the model. The instruments
being evaluated may trigger a potential loss in excess of calculated amounts if
changes in commodity prices exceed the confidence level of the model used. The
VAR methodology employs the following critical parameters: volatility estimates,
market values of open positions, appropriate market-oriented holding periods and
seasonally adjusted correlation estimates. The Company uses a holding period of
three days as the estimate of the length of time that will be needed to
liquidate the positions. The volatility and the correlation estimates measure
the impact of adverse price movements both at an individual position level as
well as at the total portfolio level. The confidence level established is 99%.
For example, if VAR is calculated at $10 million, it is estimated at a 99%
confidence level that if prices move against the Company's positions, the
Company's pre-tax gain or loss in liquidating the portfolio would not exceed $10
million in the three days that it would take to liquidate the portfolio.
The Company accounts for the sale of its electric generation in excess of
its jurisdictional needs or the purchase of jurisdictional needs as non-trading.
Non-jurisdictional purchases for resale and subsequent resales are accounted for
as energy trading contracts. With respect to the Company's trading portfolio,
the VAR was $3.2 million. The Company calculates a portfolio VAR which in
addition to its trading portfolio includes all non-trading designated contracts,
58
its generation assets excluded from jurisdictional rates and any excess
jurisdictional capacity. This excess is determined using average peak forecasts
for the respective block of power in the forward market. The Company's portfolio
VAR was $16.5 million at March 31, 2002.
The Company's VAR is regularly monitored by the Company's RMC. The RMC
has put in place procedures to ensure that increases in VAR are reviewed and, if
deemed necessary, acted upon to reduce exposures. 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.
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 RMC. The
Company provides for losses due to market and credit risk. The Company's credit
risk with its largest counterparty as of March 31, 2002 was $4.3 million.
The Company hedges certain portions of natural gas supply contracts in
order to protect its jurisdictional customers from adverse price fluctuations in
the natural gas market. The financial impact of all hedge gains and losses,
including the related costs of the program, is recoverable through the Company's
purchased gas adjustment clause as deemed prudently incurred by the PRC. As a
result, earnings are not affected by gains and losses generated by these
instruments.
Interest Rate Risk
As of March 31, 2002, the Company has an investment portfolio of
fixed-rate government obligations and corporate securities which was subject to
the risk of loss associated with movements in market interest rates. For
accounting purposes, the portfolio is classified as available-for-sale and is
marked-to-market. As a result, unrealized losses resulting from interest rate
increases are recorded as a component of comprehensive income. If interest rates
were to rise, 50 basis points from their levels at March 31, 2002, the fair
value of these instruments would decline by 0.6% or $0.9 million. In addition,
because of this interest rate sensitivity, early or unplanned redemption of
these investments in a period of increasing interest rates would subject the
Company to risk of a realized loss of principal as the fair market value of
these investments would be less than their carrying value. The Company employs
investment managers to mitigate this risk. As part of its investing strategies,
the Company has diversified its portfolio with investments of varying maturity,
obligors and limits credit exposure to high investment grade quality
investments.
The Company has long-term debt which subjects it to the risk of loss
associated with movements in market interest rates. All of the Company's
long-term debt is fixed-rate debt, and therefore, does not expose the Company's
earnings to a risk of loss due to adverse changes in market interest rates.
However, the fair value of these debts instruments would increase by
approximately 4.5% or $45.4 million if interest rates were to decline by 50
basis points from their levels at March 31, 2002. As of March 31, 2002, the fair
value of the Company's long-term debt was $1.0 billion as compared to a
book-value of $954.0 million. In general, an increase in fair value would impact
59
earnings and cash flows if the Company were to re-acquire all or a portion of
its debt instruments in the open market prior to their maturity. Certain
issuances of the Company's debt have call dates in December 2002 and August
2003. To hedge against the risk of rising interest rates and their impact on the
economies of calling the debt, the Company has entered into two forward starting
swaps in 2001 and three additional contracts in 2002. These forward interest
rate swaps effectively lock-in interest rates for the notional amount of the
debt that is callable at a rate of approximately 4.9% plus an adjustment for the
Company's and industry's credit rating. At March 31, 2002, the fair market value
of these derivative financial instruments was approximately $4.7 million in the
Company's favor.
The Company contributed $6.1 million in 2001 to a trust established to
fund decommissioning costs for PVNGS. In January 2002, the Company contributed
$23.5 million for plan year 2001 to the trust for the Company's pension plan,
and other post retirement benefits. The securities held by the trusts had an
estimated fair value of $499.4 million as of March 31, 2002, of which
approximately 28.9% were fixed-rate debt securities that subject the Company to
risk of loss of fair value with movements in market interest rates. If rates
were to increase by 50 basis points from their levels at March 31, 2002, the
decrease in the fair value of the securities would be 3.2% or $4.5 million. The
Company does not currently recover or return in jurisdictional rates losses or
gains on these securities; therefore, the Company is at risk for shortfalls in
its funding of its obligations due to investment losses. However, the Company
does not believe that long-term market returns over the period of funding will
be less than required for the Company to meet its obligations.
Equity Market Risk
As discussed above under Interest Rate Risk, the Company contributes to
trusts established to fund its share of the decommissioning costs of PVNGS and
other post retirement benefits. The trust holds certain equity securities as of
March 31, 2002. These equity securities also expose the Company to losses in
fair value. Approximately 56% of the securities held by the various trusts were
equity securities as of March 31, 2002. Similar to the debt securities held for
funding decommissioning and certain pension and other postretirement costs, the
Company does not recover or return in jurisdictional rates losses or gains on
these equity securities.
In 2001, the Company implemented an enhanced cash management strategy
using derivative instruments based on the Standard & Poors 100 and 500 indices.
The strategy is designed to capitalize on high market volatility or benefit from
market direction. An investment manager is utilized to execute the program. The
program is carefully managed by the RMC and limited to a one-day VAR of $5
million and a loss limit of $7.5 million. Trades are closed-out before the end
of a reporting period and typically within the same day of execution. Recently,
the RMC recommended and the Finance Committee approved the use of derivatives
based on the Nasdaq composite index.
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.
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NAVAJO NATION ENVIRONMENTAL ISSUES
Four Corners is located on the Navajo Reservation and is held under an
easement granted by the federal government as well as a lease from the Navajo
Nation. APS is the Four Corners operating agent and the Company owns a 13%
ownership interest in Units 4 and 5 of Four Corners.
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 "Navajo Acts"). The Navajo Acts
purport to give the Navajo Nation Environmental Protection Agency authority to
promulgate regulations covering air quality, drinking water, and pesticide
activities, including those that occur at Four Corners. The Four Corners
participants dispute that purported authority, and by letter dated October 12,
1995, the Four Corners participants requested the United States Secretary of the
Interior to resolve their dispute with the Navajo Nation regarding whether or
not the Navajo Acts apply to operations of Four Corners. On October 17, 1995,
the Four Corners participants filed a lawsuit in the District Court of the
Navajo Nation, Window Rock District, seeking, among other things, a declaratory
judgment that:
o the lease and federal easement preclude the application of the Navajo Acts
to the operations of Four Corners; and
o the Navajo Nation and its agencies and courts lack adjudicatory
jurisdiction to determine the enforceability of the Navajo Acts as applied
to Four Corners.
On October 18, 1995, the Navajo Nation and the Four Corners participants
agreed to indefinitely stay these proceedings so that the parties may attempt to
resolve the dispute without litigation. The Secretary and the Court have stayed
these proceedings pursuant to a request by the parties. The Company cannot
currently predict the outcome of this matter.
In February 1998, the EPA issued regulations identifying those Clean Air
Act provisions for which it is appropriate to treat Indian tribes in the same
manner as states. The EPA has announced that it has not yet determined whether
the Clean Air Act would supersede pre-existing binding agreements between the
Navajo Nation and the Four Corners participants that could limit the Navajo
Nation's environmental regulatory authority over Four Corners. The Company
believes that the Clean Air Act does not supersede these pre-existing
agreements. The Company cannot currently predict the outcome of this matter.
On August 8, 2000, the EPA signed an Eligibility Determination for the
Navajo Nation for Grants Under Section 105 of the Clean Air Act in which the EPA
determined that the Navajo Nation was eligible to receive grants under the Clean
Air Act. On September 8, 2001, after learning of the eligibility determination,
APS, as Four Corners operating agent, filed a Petition for Review of the EPA's
decision in the United States Court of Appeals for the Ninth Circuit in order to
ensure that the EPA's August 2000 determination not be construed to constitute a
determination of the Navajo Nation's authority to regulate Four Corners. APS v.
United States Environmental Protection Agency, No. 01-71577. APS, the EPA and
other parties have requested that the Court stay any further briefing while they
negotiate a settlement.
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In April 2000, the Navajo Tribal Council approved operating permit
regulations under the Navajo Nation Air Pollution Prevention and Control Act.
The Four Corners participants believe that the regulations fail to recognize
that the Navajo Nation did not intend to assert jurisdiction over Four Corners.
On July 12, 2000, the Four Corners participants each filed a petition with the
Navajo Supreme Court for review of the operating permit regulations. The Company
cannot currently predict the outcome of this matter.
KAFB CONTRACT
In 1999, the Company was informed that the DOE had entered into an agency
agreement with WAPA on behalf of KAFB, one of the Company's largest retail
electric customers, by which WAPA would competitively procure power for KAFB.
The proposed wholesale power procurement was to begin at the expiration of
KAFB's power service contract with the Company in December 1999. On May 4, 1999,
the Company received a request for network transmission service from WAPA
pursuant to Section 211 of the Federal Power Act to facilitate the delivery of
wholesale power to KAFB over the Company's transmission system. The Company
denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB
is and will continue to be a retail customer until the 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 rates, terms
and conditions of service, including compensation. On January 18, 2002, the
parties submitted a settlement agreement resolving most of the issues relating
to the rates, terms and conditions of service. The partial settlement reserved
one issue for FERC decision or further proceedings. The reserved issue relates
to whether WAPA is entitled to a credit against payments for transmission
service for certain facilities located near KAFB. The settlement agreement filed
at FERC reserves the Company's rights to seek rehearing and judicial review of
any final order and to present other legal claims. On April 12, 2002, the FERC
approved the settlement. On April 29, 2002, the FERC issued its final order
directing the Company to provide service. The Company is evaluating its legal
options in relation to the 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 and KAFB continues to purchase
retail service pending resolution of all relevant issues. The PRC case has been
held in abeyance, pending the outcome of the FERC proceeding.
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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 in 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 and Local 611 are scheduled to arbitrate the dispute in late May
2002. The Company is unable to predict the outcome of this matter.
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 would acquire the Western Resources electric utility operations in a
tax-free, stock-for-stock transaction. The agreement required that Western
Resources split-off its non-utility businesses to its shareholders prior to
closing.
In July, 2001, the KCC issued two orders. The first order declared the
split-off required by the agreement to be unlawful as designed, with or without
a merger. The second order decreased rates for Western Resources, despite a
request for $151 million increase. After rehearing the KCC established the rate
decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on
Reconsideration reaffirming its decision that the split-off as designed in the
agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001 in New York state court
seeking declarations that the transaction could not be accomplished as designed
63
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 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.
On November 19, 2001, Western Resources filed a complaint against the
Company in New York state court alleging breach of contract and breach of
implied covenant of good faith and fair dealing. Western Resources alleged that
the Company brought about the KCC orders, failed to assist in efforts to reverse
the KCC orders, refused to renegotiate within the terms of the agreement,
interfered with Western Resources' efforts to satisfy the terms of the
agreement, and effected an unauthorized de facto termination of the agreement by
filing its complaint. Western Resources alleges damages in excess of $650
million. The Company believes that the complaint filed by Western Resources is
without merit and intends to vigorously defend itself against the complaint. The
Company also intends to vigorously pursue its own complaint.
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect.
On February 5, 2002, the District Court for Shawnee County, Kansas,
dismissed without prejudice Western Resources' appeal of the KCC's split-off
orders. The Court ruled that, by filing a new financial plan in compliance with
the orders, Western Resources accepted certain portions of the orders thereby
creating a situation where further administrative action became necessary. As a
result, the Court concluded that the matter was not ripe for judicial review and
remanded the case to the KCC.
On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate
order. On April 8, 2002, Western Resources filed with the Kansas Supreme Court a
Petition for Review of the Court of Appeals decision.
On May 2, 2002, the New York court issued an order denying Western
Resources' motion for stay or dismissal of the Company's complaint. At the same
time, the court granted the Company's motion to dismiss Western Resources'
complaint, without prejudice. As a result, the Company has been determined to be
the plaintiff in the litigation but Western Resources will be allowed, when it
files its answer, to reassert its claims against the Company as affirmative
defenses or counterclaims, if it so chooses.
On May 10, 2002, the Company filed an Amended Complaint seeking
unspecified damages from Western Resources for numerous breaches of contract
related to the determination that the split-off required by the agreement was
unlawful and required prior approval by the KCC. The Company also seeks
unspecified damages for additional breaches of contract because: Western
Resources failed to provide the Company with the opportunity to review and
comment on information related to the transaction provided by Western Resources
to third parties; Western Resources failed to obtain the Company's consent to
amend existing employee compensation and benefits plans or create new ones; and
Western Resources filed for approval of an alternative debt reduction plan that
represents the abandonment of the split-off required by the agreement. In
addition the Company seeks numerous declarations from the court, including that
the Company was not obligated to perform because conditions regarding
performance were not satisfied; the Company did not breach when it terminated
the agreement; and the rate case order constitutes a material adverse effect
under the terms of the agreement.
The Company is unable to predict the ultimate outcome of its litigation
with Western Resources.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
15.0 Letter Re: Unaudited Interim Financial Information
b. Reports on Form 8-K:
Report dated and filed April 5, 2002 reporting the Company expects lower prices
will reduce 2002 earnings.
Report dated and filed April 9, 2002 reporting the Company's Comparative
Operating Statistics for the month of March 2002 and 2001 and the year ended
March 31, 2002 and 2001.
Report dated and filed April 19, 2002 reporting the Company's notice of annual
meeting proxy statement relating to its annual shareholders meeting to be held
on May 14, 2002.
Report dated and filed April 24, 2002 reporting the Company's Quarter and Three
Months Ended March 31, 2002 Earnings Announcement and Consolidated Statement of
Earnings.
Report dated and filed May 10, 2002 reporting the Company's Comparative
Operating Statistics for the month of April 2002 and 2001 and the year ended
April 30, 2002 and 2001.
65
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.
PNM RESOURCES, INC. AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
---------------------------------------------
(Registrants)
Date: May 15, 2002 /s/ John R. Loyack
---------------------------------------------
John R. Loyack
Vice President, Corporate Controller
and Chief Accounting Officer
(Officer duly authorized to sign this report)
66