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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
SECURITIES EXCHANGE ACT OF 1934
For the period ended September 30, 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 Mexic 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 November 1, 2002
- ---------- ----- -------------------------------
PNM Resources, Inc. Common Stock, 39,117,799
No Par Value
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
INDEX
Page No.
PART I. FINANCIAL INFORMATION:
Reports of Independent Public Accountants............................... 3
ITEM 1. FINANCIAL STATEMENTS
PNM Resources, Inc. and Subsidiaries
Consolidated Statements of Earnings
Three and Nine Months Ended September 30, 2002 and 2001...... 7
Consolidated Balance Sheets
September 30, 2002 and December 31, 2001..................... 8
Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2002 and 2001................ 10
Consolidated Statements of Comprehensive Income
Three and Nine Months Ended September 30, 2002 and 2001...... 11
Public Service Company of New Mexico
Consolidated Statements of Earnings
Three and Nine Months Ended September 30, 2002 and 2001...... 12
Consolidated Balance Sheets
September 30, 2002 and December 31, 2001..................... 13
Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2002 and 2001................ 15
Consolidated Statements of Comprehensive Income
Three and Nine Months Ended September 30, 2002 and 2001...... 16
Notes to Consolidated Financial Statements........................... 17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS............... 34
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK................................................. 79
ITEM 4. CONTROLS AND PROCEDURES........................................ 86
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS.............................................. 87
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................... 92
Signature.................................................................. 94
Certifications............................................................. 95
2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of PNM Resources, Inc.
Albuquerque, New Mexico
We have reviewed the accompanying condensed consolidated balance sheet of PNM
Resources, Inc. and subsidiaries (the Company) as of September 30, 2002, and the
related condensed consolidated statements of earnings and comprehensive income
for the three-month and nine-month periods ended September 30, 2002 and of cash
flows for the nine-month period ended September 30, 2002.
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 of 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 of America, 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 such consolidated financial statements as of September 30, 2002, and
for the three- and nine-month periods then ended for them to be in conformity
with accounting principles generally accepted in the United States of America.
The accompanying financial information as of December 31, 2001, and for the
three- and nine-month periods ended September 30, 2001, were not audited or
reviewed by us and, accordingly, we do not express an opinion or any other form
of assurance on them.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
October 29, 2002
3
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of Public Service Company of New
Mexico Albuquerque, New Mexico
We have reviewed the accompanying condensed consolidated balance sheet of Public
Service Company of New Mexico (the Company) as of September 30, 2002, and the
related condensed consolidated statements of earnings and comprehensive income
for the three-month and nine-month periods ended September 30, 2002 and of cash
flows for the nine-month period ended September 30, 2002.
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 of 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 of America, 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 such consolidated financial statements as of September 30, 2002, and
for the three- and nine-month periods then ended for them to be in conformity
with accounting principles generally accepted in the United States of America.
The accompanying financial information as of December 31, 2001, and for the
three- and nine-month periods ended September 30, 2001, were not audited or
reviewed by us and, accordingly, we do not express an opinion or any other form
of assurance on them.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
October 29, 2002
4
This is a copy of a report previously issued by Arthur Andersen LLP. The report
has not been reissued by Arthur Andersen LLP nor has Arthur Andersen LLP
provided an awareness letter for the inclusion of its report in this Quarterly
Report on Form 10-Q. The report was issued prior to the formation of PNM
Resources, Inc., the holding company of Public Service Company of New Mexico.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of Public Service Company of New Mexico:
We have reviewed the accompanying condensed consolidated balance sheet of PUBLIC
SERVICE COMPANY OF NEW MEXICO (a New Mexico corporation) and subsidiaries as of
September 30, 2001, and the related condensed consolidated statements of
earnings and comprehensive income for the three-month and nine-month periods
ended September 30, 2001 and 2000, and the condensed consolidated statements of
cash flows for the nine-month periods ended September 30, 2001 and 2000. These
financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States, the objective
of which is the expression of an opinion regarding the financial statements
taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the financial statements referred to above for them to be in
conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards generally
accepted in the United States, the consolidated balance sheet and statement of
capitalization of Public Service Company of New Mexico and subsidiaries as of
December 31, 2000, and the related consolidated statements of earnings, and cash
flows for the year then ended (not presented separately herein), and in our
report dated January 26, 2001, we expressed an unqualified opinion on those
financial statements. In our opinion, the information set forth in the
accompanying condensed consolidated balance sheet as of December 31, 2000 is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
November 13, 2001
5
This is a copy of a report previously issued by Arthur Andersen LLP. The report
has not been reissued by Arthur Andersen LLP nor has Arthur Andersen LLP
provided a consent to the inclusion of its report in this Quarterly Report on
Form 10-Q.
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 audited the accompanying consolidated balance sheets and statements of
capitalization of PNM Resources, Inc. (a New Mexico Corporation) and
subsidiaries and Public Service Company of New Mexico and subsidiaries (a New
Mexico Corporation) as of December 31, 2001 and 2000, and the related
consolidated statements of earnings, cash flows and comprehensive income for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Companies' management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of PNM Resources, Inc. and
subsidiaries and Public Service Company of New Mexico and subsidiaries as of
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001 in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
February 1, 2002
6
ITEM 1. FINANCIAL STATEMENTS
PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------- -------------------------------
2002 2001 2002 2001
-------------- -------------- -------------- --------------
(In thousands, except per share amounts)
Operating Revenues:
Electric.................................. $252,861 $582,066 $677,340 $1,704,390
Gas....................................... 36,244 39,649 189,413 318,670
Unregulated businesses.................... 335 180 1,252 1,456
-------------- -------------- -------------- --------------
Total operating revenues................ 289,440 621,895 868,005 2,024,516
-------------- -------------- -------------- --------------
Operating Expenses:
Cost of energy sold....................... 133,410 429,965 411,210 1,360,904
Administrative and general................ 38,041 39,241 106,494 117,494
Energy production costs................... 35,238 36,224 104,411 109,128
Depreciation and amortization............. 25,780 24,194 75,776 72,343
Transmission and distribution costs....... 15,949 18,402 47,937 48,760
Taxes, other than income taxes............ 7,077 6,380 24,589 21,436
Income taxes.............................. 4,810 20,067 16,317 89,182
-------------- -------------- -------------- --------------
Total operating expenses................ 260,305 574,473 786,734 1,819,247
-------------- -------------- -------------- --------------
Operating income........................ 29,135 47,422 81,271 205,269
-------------- -------------- -------------- --------------
Other Income and Deductions:
Other income.............................. 12,194 12,766 35,200 39,995
Other deductions.......................... (5,235) (9,456) (6,182) (54,191)
Income tax (expense) benefit.............. (2,541) (2,277) (10,815) 3,275
-------------- -------------- -------------- --------------
Net other income and deductions......... 4,418 1,033 18,203 (10,921)
-------------- -------------- -------------- --------------
Earnings before interest charges........ 33,553 48,455 99,474 194,348
-------------- -------------- -------------- --------------
Interest Charges............................ 15,756 15,680 45,571 48,424
-------------- -------------- -------------- --------------
Net Earnings................................ 17,797 32,775 53,903 145,924
Preferred Stock Dividend Requirements....... 147 147 440 440
-------------- -------------- -------------- --------------
Net Earnings Applicable to Common Stock..... $ 17,650 $ 32,628 $ 53,463 $ 145,484
============== ============== ============== ==============
Net Earnings per Common Share:
Basic..................................... $ 0.45 $ 0.83 $ 1.37 $ 3.72
============== ============== ============== ==============
Diluted................................... $ 0.45 $ 0.82 $ 1.35 $ 3.66
============== ============== ============== ==============
Dividends Paid per Share of Common Stock.... $ 0.22 $ 0.20 $ 0.64 $ 0.60
============== ============== ============== ==============
The accompanying notes are an integral part of these
condensed financial statements.
7
PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2002 2001
-------------- -------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service....................................... $2,201,768 $2,118,417
Gas plant in service............................................ 615,979 575,350
Common plant in service and plant held for future use........... 47,540 45,223
------------- -------------
2,865,287 2,738,990
Less accumulated depreciation and amortization.................. 1,310,747 1,234,629
------------- -------------
1,554,540 1,504,361
Construction work in progress................................... 228,390 249,656
Nuclear fuel, net of accumulated amortization of
$19,327 and $16,954......................................... 29,942 26,940
------------- -------------
Net utility plant............................................. 1,812,872 1,780,957
------------- -------------
Other Property and Investments:
Other investments............................................... 404,998 552,453
Non-utility property, net of accumulated depreciation of
$1,708 and $1,580........................................... 1,571 1,784
------------- -------------
Total other property and investments.......................... 406,569 554,237
------------- -------------
Current Assets:
Cash and cash equivalents....................................... 29,991 26,057
Accounts receivables, net of allowance for uncollectible
accounts of $15,575 and $18,025............................. 118,264 147,787
Other receivables............................................... 38,644 52,158
Inventories..................................................... 36,613 36,483
Regulatory assets............................................... 120 10,473
Short-term investments.......................................... 109,469 45,111
Other current assets............................................ 25,906 31,428
------------- -------------
Total current assets.......................................... 359,007 349,497
------------- -------------
Deferred Charges:
Regulatory assets............................................... 199,764 197,948
Prepaid retirement costs........................................ 39,628 18,273
Other deferred charges.......................................... 89,458 33,726
------------- -------------
Total deferred charges........................................ 328,850 249,947
------------- -------------
$2,907,298 $2,934,638
============= =============
The accompanying notes are an integral part of these condensed
financial statements.
8
PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2002 2001
-------------- --------------
(Unaudited)
CAPITALIZATION AND LIABILITIES In thousands)
Capitalization:
Common stockholders' equity:
Common stock................................................... $ 622,723 $ 625,632
Accumulated other comprehensive loss, net of tax............... (40,810) (28,996)
Retained earnings.............................................. 451,640 415,388
-------------- --------------
Total common stockholders' equity........................... 1,033,553 1,012,024
Minority interest................................................. 11,538 11,652
Cumulative preferred stock without mandatory
redemption requirements...................................... 12,800 12,800
Long-term debt.................................................... 953,926 953,884
-------------- --------------
Total capitalization........................................ 2,011,817 1,990,360
-------------- --------------
Current Liabilities:
Short-term debt.................................................... 100,000 35,000
Accounts payable.................................................... 99,528 120,918
Accrued interest and taxes.......................................... 59,833 72,022
Other current liabilities........................................... 55,702 101,697
-------------- --------------
Total current liabilities................................... 315,063 329,637
-------------- --------------
Deferred Credits:
Accumulated deferred income taxes................................... 111,670 120,153
Accumulated deferred investment tax credits......................... 42,366 44,714
Regulatory liabilities.............................................. 53,814 52,890
Regulatory liabilities related to accumulated deferred income tax... 14,163 14,163
Accrued postretirement benefit costs................................ 15,198 14,929
Other deferred credits.............................................. 343,207 367,792
-------------- --------------
Total deferred credits....................................... 580,418 614,641
-------------- --------------
$2,907,298 $2,934,638
============== ==============
The accompanying notes are an integral part of these
condensed financial statements.
9
PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
--------------------------
2002 2001
------------ ------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings...................................................... $ 53,903 $ 145,924
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization................................. 85,625 80,086
Other, net.................................................... (25,276) 15,413
Changes in certain assets and liabilities:
Accounts receivables........................................ 29,523 (19,497)
Other assets................................................ 907 36,490
Accounts payable............................................ (21,390) (51,714)
Accrued taxes............................................... (10,369) 80,907
Other liabilities........................................... (8,889) 9,251
------------ ------------
Net cash flows provided by operating activities............. 104,034 296,860
------------ ------------
Cash Flows From Investing Activities:
Utility plant additions........................................... (166,640) (165,127)
Redemption of short-term investments.............................. 45,000 -
Return of principal of PVNGS lessor notes......................... 17,531 16,674
Other............................................................. (32,493) (5,440)
------------ ------------
Net cash flows used for investing activities................ (136,602) (153,893)
------------ ------------
Cash Flows From Financing Activities:
Borrowings........................................................ 65,000 -
Exercise of employee stock options................................ (2,909) (3,589)
Dividends paid.................................................... (25,475) (23,905)
Other............................................................. (114) (559)
------------ ------------
Net cash flows provided by (used for) financing activities.. 36,502 (28,053)
------------ ------------
Increase in Cash and Cash Equivalents............................... 3,934 114,914
Beginning of Period................................................. 26,057 107,691
------------ ------------
End of Period....................................................... $ 29,991 $222,605
============ ============
Supplemental Cash Flow Disclosures:
Interest paid..................................................... $ 45,610 $ 48,298
============ ============
Capitalized interest.............................................. $ 5,465 $ -
============ ============
Income taxes paid, net............................................ $ 43,534 $ 56,150
============ ============
The accompanying notes are an integral part of these
condensed financial statements.
10
PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands)
Net Earnings......................................... $ 17,797 $32,775 $ 53,903 $145,924
------------ ------------ ------------ ------------
Other Comprehensive Income (Loss),
net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses) arising
during the period........................... 3,381 (1,459) 1,189 (885)
Reclassification adjustment for
(gains) losses included in net income....... (49) 341 (475) (693)
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.................. (12,963) (33,385) (13,303) (3,278)
Reclassification adjustment for
(gains) losses in net income................ (141) 15,455 775 (5,031)
------------ ------------ ------------ ------------
Total Other Comprehensive Loss....................... (9,772) (19,048) (11,814) (2,959)
------------ ------------ ------------ ------------
Total Comprehensive Income........................... $8,025 $ 13,727 $ 42,089 $142,965
============ ============ ============ ============
The accompanying notes are an integral part of these
condensed financial statements.
11
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands)
Operating Revenues:
Electric..................................... $252,861 $582,066 $677,340 $1,704,390
Gas.......................................... 36,244 39,649 189,413 318,670
Unregulated businesses....................... - 180 - 1,456
------------ ------------ ------------ ------------
Total operating revenues................... 289,105 621,895 866,753 2,024,516
------------ ------------ ------------ ------------
Operating Expenses:
Cost of energy sold.......................... 132,599 429,965 410,399 1,360,904
Administrative and general................... 40,768 39,241 104,510 117,494
Energy production costs...................... 35,238 36,224 104,411 109,128
Depreciation and amortization................ 25,541 24,194 75,294 72,343
Transmission and distribution costs.......... 15,949 18,402 47,937 48,760
Taxes, other than income taxes............... 7,529 6,380 23,610 21,436
Income taxes................................. 8,209 20,067 20,714 89,182
------------ ------------ ------------ ------------
Total operating expenses................... 265,833 574,473 786,875 1,819,247
------------ ------------ ------------ ------------
Operating income........................... 23,272 47,422 79,878 205,269
------------ ------------ ------------ ------------
Other Income and Deductions:
Other income................................. 9,656 12,766 29,149 39,995
Other deductions............................. (2,992) (9,456) (6,744) (54,191)
Income tax (expense) benefit................. (1,986) (2,277) (8,870) 3,275
------------ ------------ ------------ ------------
Net other income and deductions............ 4,678 1,033 13,535 (10,921)
------------ ------------ ------------ ------------
Earnings before interest charges........... 27,950 48,455 93,413 194,348
Interest Charges............................... 15,788 15,680 45,744 48,424
------------ ------------ ------------ ------------
Net Earnings Before Preferred Stock Dividends 12,162 32,775 47,669 145,924
Preferred Stock Dividend Requirements.......... 147 147 440 440
------------ ------------ ------------ ------------
Net Earnings................................... $ 12,015 $ 32,628 $ 47,229 $ 145,484
============ ============ ============ ============
The accompanying notes are an integral part of these
condensed financial statements.
12
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2002 2001
-------------- -------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service..................................... $2,201,768 $2,118,417
Gas plant in service.......................................... 615,979 575,350
Common plant in service and plant held for future use......... 18,661 45,223
-------------- -------------
2,836,408 2,738,990
Less accumulated depreciation and amortization................ 1,306,896 1,234,629
-------------- -------------
1,529,512 1,504,361
Construction work in progress................................. 220,314 249,656
Nuclear fuel, net of accumulated amortization of
$19,327 and $16,954....................................... 29,942 26,940
-------------- -------------
Net utility plant........................................... 1,779,768 1,780,957
-------------- -------------
Other Property and Investments:
Other investments............................................. 399,822 446,784
Non-utility property, net of accumulated depreciation of
zero and $1,580........................................... 966 1,784
-------------- -------------
Total other property and investments........................ 400,788 448,568
-------------- -------------
Current Assets:
Cash and cash equivalents..................................... 20,418 14,677
Accounts receivables, net of allowance for uncollectible
accounts of $15,575 and $18,025........................... 118,264 147,787
Other receivables............................................. 37,716 52,158
Inventories................................................... 36,610 36,483
Regulatory assets............................................. 120 10,473
Short-term investments........................................ - 45,111
Other current assets.......................................... 16,150 21,477
-------------- -------------
Total current assets........................................ 229,278 328,166
-------------- -------------
Deferred Charges:
Regulatory assets............................................. 199,736 187,475
Prepaid retirement costs...................................... 39,628 18,273
Other deferred charges........................................ 89,293 44,199
-------------- -------------
Total deferred charges...................................... 328,657 249,947
-------------- -------------
$2,738,491 $2,807,638
============== =============
The accompanying notes are an integral part of these condensed
financial statements.
13
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2002 2001
------------- -------------
Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands)
Capitalization:
Common stockholder's equity:
Common stock.................................................... $ 195,589 $ 195,589
Additional paid-in capital...................................... 430,043 430,043
Accumulated other comprehensive loss, net of tax................ (40,230) (28,996)
Retained earnings............................................... 241,756 288,388
------------- -------------
Total common stockholder's equity............................ 827,158 885,024
Minority interest.................................................. 11,538 11,652
Cumulative preferred stock without mandatory
redemption requirements....................................... 12,800 12,800
Long-term debt..................................................... 953,926 953,884
------------- -------------
Total capitalization......................................... 1,805,422 1,863,360
------------- -------------
Current Liabilities:
Short-term debt.................................................... 100,000 35,000
Intercompany debt.................................................. 21,319 -
Accounts payable................................................... 91,606 120,918
Intercompany accounts payable...................................... 14,290 -
Accrued interest and taxes......................................... 72,875 72,022
Other current liabilities.......................................... 56,392 101,697
------------- -------------
Total current liabilities.................................... 356,482 329,637
------------- -------------
Deferred Credits:
Accumulated deferred income taxes.................................... 113,582 120,153
Accumulated deferred investment tax credits.......................... 42,366 44,714
Regulatory liabilities............................................... 53,814 52,890
Regulatory liabilities related to accumulated deferred income tax.... 14,163 14,163
Accrued postretirement benefit costs................................. 15,198 14,929
Other deferred credits............................................... 337,464 367,792
------------- -------------
Total deferred credits............................................ 576,587 614,641
------------- -------------
$2,738,491 $2,807,638
============= =============
The accompanying notes are an integral part of these
condensed financial statements.
14
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
---------------------------
2002 2001
------------ ------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings........................................................ $ 47,669 $ 145,924
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization................................... 85,143 80,086
Other, net...................................................... (24,997) 15,413
Changes in certain assets and liabilities:
Accounts receivables.......................................... 29,523 (19,497)
Other assets.................................................. 3,573 36,490
Accounts payable.............................................. (29,312) (51,714)
Accrued taxes................................................. 3,480 80,907
Other liabilities............................................. (44,179) 9,251
------------ ------------
Net cash flows provided by operating activities............... 70,900 296,860
------------ ------------
Cash Flows Used for Investing Activities:
Utility plant additions............................................. (159,396) (165,127)
Redemption of short-term investments................................ 45,000 -
Return of principal of PVNGS lessor notes........................... 17,531 16,674
Other investing..................................................... (17,192) (5,440)
------------ ------------
Net cash flows used for investing activities.................. (114,057) (153,893)
------------ ------------
Cash Flows Used for Financing Activities:
Borrowings.......................................................... 65,000 -
Exercise of employee stock options.................................. - (3,589)
Dividends paid...................................................... (51,597) (23,905)
Other financing..................................................... (114) (559)
Change in intercompany accounts..................................... 35,609 -
------------ ------------
Net cash flows provided by (used by) financing activities..... 48,898 (28,053)
------------ ------------
Increase in Cash and Cash Equivalents................................. 5,741 114,914
Beginning of Period................................................... 14,677 107,691
------------ ------------
End of Period......................................................... $ 20,418 $222,605
============ ============
Supplemental Cash Flow Disclosures:
Interest paid....................................................... $ 45,776 $ 48,298
============ ============
Capitalized interest................................................ $ 5,465 $ -
============ ============
Income taxes paid, net ............................................. $ 31,514 $ 56,150
============ ============
The accompanying notes are an integral part of these condensed
financial statements.
15
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- ---------------------------
2002 2001 2002 2001
----------- ------------ ------------ ------------
(In thousands)
Net Earnings......................................... $ 12,162 $ 32,775 $47,669 $145,924
----------- ------------ ------------ ------------
Other Comprehensive Income (Loss),
net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses) arising
during the period............................ 507 (1,459) 737 (885)
Reclassification adjustment for
(gains) losses included in net income....... (49) 341 (475) (693)
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.................. (11,932) (33,385) (12,271) (3,278)
Reclassification adjustment for
(gains) losses in cash flow hedges........... (141) 15,455 775 (5,031)
----------- ------------ ------------ ------------
Total Other Comprehensive Loss....................... (11,615) (19,048) (11,234) (2,959)
----------- ------------ ------------ ------------
Total Comprehensive Income........................... $ 547 $ 13,727 $36,435 $142,965
=========== ============ ============ ============
The accompanying notes are an integral part of these
condensed financial statements.
16
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Company Overview
PNM Resources, Inc. (the "Holding Company") is an investor-owned holding
company of energy and energy related companies. Its principal subsidiary, Public
Service Company of New Mexico ("PNM"), is an integrated public utility primarily
engaged in the generation, transmission, distribution and sale and trading of
electricity; the 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.
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Holding Company, the Holding Company became the parent
company of PNM. Prior to the share exchange, the Holding Company had existed as
a subsidiary of PNM. The new parent company began trading on the New York Stock
Exchange under the PNM symbol beginning on December 31, 2001.
(2) Accounting Policies and Responsibilities for Financial Statements
In the opinion of management of the Holding Company and PNM, the
accompanying interim consolidated financial statements present fairly the
Companies' financial position at September 30, 2002 and December 31, 2001, the
consolidated results of their operations for the three and nine months ended
September 30, 2002 and 2001 and the consolidated statements of cash flows for
the nine months ended September 30, 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 Companies'
annual consolidated financial statements have been condensed or omitted, as
permitted under the applicable SEC rules and regulations. Readers of these
statements should refer to the Companies' audited consolidated financial
statements and notes for the year ended December 31, 2001, which are included in
the Companies' 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.
(3) Presentation
The Notes to Consolidated Financial Statements of PNM Resources, Inc. and
Subsidiaries and PNM (collectively the "Company") are presented on a combined
basis. The 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 of PNM were
dividended to the Holding Company pursuant to an order from the New Mexico
Public Regulation Commission ("PRC"). Readers of the Notes to Consolidated
Financial Statements should assume that the information presented applies to the
consolidated results of operations and financial position of both PNM Resources,
Inc. and Subsidiaries and PNM, except where the context or references clearly
indicate otherwise. Discussions regarding specific contractual obligations
generally reference the company that is legally obligated.
17
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In the case of contractual obligations of PNM, these obligations are
consolidated with PNM Resources, Inc. and Subsidiaries under generally accepted
accounting principles ("GAAP"). Broader operational discussion refers to the
Company.
(4) Segment Information
As it currently operates, 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 due to its immateriality and is combined with the
distribution business line for disclosure purposes.
UTILITY OPERATIONS
Electric
PNM provides retail electric service, regulated by the PRC, to a large
area of north central New Mexico, including the cities of Albuquerque and Santa
Fe, and certain other areas of New Mexico. PNM 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 Generation and Trading. Intersegment purchases from Generation and Trading
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 delivery and production that includes certain
generation assets that are part of Generation and Trading plus a rate of return.
Gas
PNM's gas operations distribute natural gas to most of the major
communities in New Mexico, including Albuquerque and Santa Fe. PNM's customer
base includes both sales-service customers and transportation-service customers.
Customer rates for gas service are set by the PRC based on the recovery of the
cost of delivering gas plus a rate of return, with the cost of gas procured for
customers being passed through to customers through a purchased gas adjustment
clause ("PGAC").
In the first quarter of 2001, Generation and Trading procured its gas
fuel supply from Gas. Beginning with the second quarter of 2001, Generation and
Trading began procuring its gas supply independently of Gas and contracted with
Gas for transportation services only.
18
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
GENERATION AND TRADING OPERATIONS
Generation and Trading serves four principal markets. These include sales
to PNM's Utility Operations to cover retail electric demand, sales to
firm-requirement 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, PNM purchases power in the open market. As of September 30,
2002, the total net generation capacity of facilities owned or leased by PNM was
1,733 MW, including a 132 MW power purchase contract accounted for as an
operating lease.
UNREGULATED
The Holding 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 Holding 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 union employees;
fluctuations in fuel, purchased power and gas prices; the actions of utility
regulatory commissions; changes in law and environmental regulations; the
performance of PNM's generating units and the success of any generation
expansion and external factors such as the weather. In the early 1990s, federal
and state policymakers began investigating and implementing major reforms
regarding the public utility industry, designed to transform electric generation
into a competitive business separate from the regulated monopoly businesses of
transmission and distribution, at least on a functional basis. These reforms
introduced new risks into the Company's business which had the potential to
impact future results, such as the Company's 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. However, as a result of the energy crisis in
California, plans for restructuring the industry are undergoing fundamental
review. The 2003 session of the New Mexico Legislature will review the
introduction of bills to repeal existing legislation providing for customer
choice and competition in retail electric power supplies, currently scheduled to
commence in 2007. Any reforms that may be made to existing plans for
restructuring the industry will also affect the Company's future results. In
addition to the fate of retail electric competition in New Mexico, the Company's
future results will continue to be affected on the wholesale side by the market
price of electricity and natural gas costs, and the results of federal reforms
regarding the wholesale market and transmission service.
19
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summarized financial information by business segment for the three months
ended September 30, 2002 and 2001 is as follows:
Utility
---------------------------------- Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2002:
Operating revenues:
External customers............. $156,363 $36,244 $192,607 $ 96,497 $ 336 $ 289,440
Intersegment revenues.......... 177 666 843 96,592 (97,435) -
Depreciation and amortization..... 8,338 5,160 13,498 11,107 1,175 25,780
Interest income................... 40 - 40 1,544 10,872 12,456
Interest charges.................. 6,060 3,494 9,554 4,657 1,545 15,756
Operating income (loss)........... 18,095 (946) 17,149 11,232 754 29,135
Income tax expense (benefit)
from continuing operations...... 7,760 (2,976) 4,784 4,071 (1,504) 7,351
Segment net income (loss)......... 11,841 (4,539) 7,302 6,242 4,253 17,797
Total assets...................... 787,759 441,370 1,229,129 1,445,787 232,382 2,907,298
Gross property additions
(deletions).................... 11,422 33,746 45,168 (10,850) 4,541 38,859
2001:
Operating revenues:
External customers............. $153,535 $39,649 $193,184 $428,531 $ 180 $ 621,895
Intersegment revenues.......... 177 - 177 95,413 (95,590) -
Depreciation and amortization..... 8,219 5,400 13,619 10,565 10 24,194
Interest income................... 555 127 682 9,841 1,585 12,108
Interest charges.................. 5,611 2,423 8,034 4,471 3,175 15,680
Operating income (loss)........... 17,235 (138) 17,097 32,217 (1,892) 47,422
Income tax expense (benefit)
from continuing operations...... 7,486 (1,914) 5,572 21,122 (4,350) 22,344
Segment net income (loss)......... 11,423 (2,923) 8,500 32,229 (7,954) 32,775
Total assets...................... 799,607 466,550 1,266,157 1,522,354 234,045 3,022,556
Gross property additions.......... 18,577 11,378 29,955 14,856 4,375 49,186
20
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summarized financial information by business segment for the nine months
ended September 30, 2002 and 2001 is as follows:
Utility
--------------------------------- Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2002:
Operating revenues:
External customers............. $431,929 $189,413 $621,342 $245,411 $ 1,252 $ 868,005
Intersegment revenues.......... 530 1,136 1,666 264,554 (266,220) -
Depreciation and amortization..... 25,239 15,548 40,787 32,587 2,402 75,776
Interest income................... 395 21 416 2,339 31,203 33,958
Interest charges.................. 17,632 10,128 27,760 11,528 6,283 45,571
Operating income.................. 46,842 10,931 57,773 21,650 1,848 81,271
Income tax expense
from continuing operations...... 18,958 1,342 20,300 6,355 477 27,132
Segment net income................ 28,930 2,048 30,978 9,698 13,227 53,903
Total assets...................... 787,759 441,370 1,229,129 1,445,787 232,382 2,907,298
Gross property additions.......... 37,888 51,324 89,212 69,581 7,847 166,640
2001:
Operating revenues:
External customers............. $424,249 $318,670 $742,919 $1,280,141 $ 1,456 $2,024,516
Intersegment revenues.......... 530 - 530 259,726 (260,256) -
Depreciation and amortization..... 24,310 16,023 40,333 31,981 29 72,343
Interest income................... 1,555 677 2,232 29,546 5,467 37,245
Interest charges.................. 14,163 8,365 22,528 22,661 3,235 48,424
Operating income (loss)........... 45,275 12,665 57,940 149,017 (1,688) 205,269
Income tax expense (benefit)
from continuing operations...... 19,564 2,775 22,339 86,682 (23,114) 85,907
Segment net income (loss)......... 29,854 4,234 34,088 132,273 (20,437) 145,924
Total assets...................... 799,607 466,550 1,266,157 1,522,354 234,045 3,022,556
Gross property additions.......... 47,082 28,836 75,918 78,674 10,535 165,127
(5) 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.
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 September 30, 2002 was $3.9 million.
21
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Natural Gas Contracts
Pursuant to a 1997 order issued by the New Mexico Public Utility
Commission ("NMPUC"), predecessor to the PRC, PNM has 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 PGAC. 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 the risk of price fluctuation during the 2002-2003 heating
season. PNM expended $6.0 million to purchase options that limit the maximum
amount PNM will pay for gas during the winter heating season. PNM is recovering
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 nine months ended September 30, 2002, Generation and Trading
settled forward trading contracts for the sale of electricity that generated
$31.3 million of electric revenues by delivering 812,645 MWh. The Company
purchased $55.4 million or 966,420 MWh of electricity under forward trading
contracts to support these contractual sales and other open market sales
opportunities. For the nine months ended September 30, 2001, Generation and
Trading settled forward trading contracts for the sale of electricity that
generated $70.7 million of electric revenues by delivering 320,000 MWh. The
Company purchased $69.5 million or 300,000 MWh of electricity under forward
trading contracts to support these contractual sales and other open market sales
opportunities.
As of September 30, 2002, PNM had open trading contract positions to buy
$38.3 million and to sell $29.6 million of electricity. At September 30, 2002,
PNM had a gross mark-to-market gain (asset position) on these trading contracts
of $4.6 million and gross mark-to-market loss (liability position) of $12.9
million, with a net mark-to-market loss (liability position) of $8.3 million.
The change in mark-to-market valuation recognized in earnings was a $22.1
million gain and a $26.8 million loss for the nine months ended September 30,
2002 and 2001, respectively.
In addition, Generation and Trading entered into forward physical
contracts for the sale of PNM's electric capacity in excess of its retail and
wholesale firm requirement needs, including reserves, or the purchase of retail
and wholesale firm requirements needs, including reserves, when resource
shortfalls exist. The Company generally accounts for these derivative financial
instruments as normal sales and purchases as defined by Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended ("SFAS 133"). PNM from time to time makes forward
purchases to serve its retail needs when the cost of purchased power is less
than the incremental cost of its generation. At September 30, 2002, PNM had open
forward positions classified as normal sales of electricity of $36.1 million and
normal purchases of electricity of $70.6 million.
22
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Generation and Trading, including both firm commitments and trading
activities, are managed through an asset backed strategy, whereby PNM's
aggregate net open position is covered by its own excess generation
capabilities. PNM is exposed to market risk if its generation capabilities were
disrupted or if its retail load requirements were greater than anticipated. If
PNM 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 that 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 the current low interest rates, PNM
entered into five forward starting interest rate swaps in the fourth quarter of
2001 and 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 at
4.95% 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. For the
nine months ended September 30, 2002, PNM recognized $0.4 million of hedge
ineffectiveness in earnings. At September 30, 2002, the fair market value of
these derivative financial instruments was approximately $20.3 million
unfavorable to the Company.
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 benchmark. The five forward starting
interest rate swaps have a termination date of May 15, 2003 for a combined
notional amount of $182.0 million. There were no fees on the transaction, as
they are imbedded in the rates, and the transaction 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.
23
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Earnings Per Share
In accordance with SFAS No. 128, Earnings per Share, dual presentation of
basic and diluted earnings per share has been presented in the Consolidated
Statements of Earnings. The following reconciliation illustrates the impact on
the share amounts of potential common shares and the earnings per share amounts
for September 30 (in thousands, except per share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2002 2001 2002 2001
------------ ----------- ----------- ------------
Basic:
Net Earnings.......................................... $ 17,797 $32,775 $53,903 $ 145,924
Preferred Stock Dividend Requirements................. 147 147 440 440
------------ ----------- ----------- ------------
Net Earnings Applicable to Common Stock............... $ 17,650 $32,628 $53,463 $ 145,484
============ =========== =========== ============
Average Number of Common Shares Outstanding........... 39,118 39,118 39,118 39,118
============ =========== =========== ============
Net Earnings per Common Share (Basic)................. $ 0.45 $ 0.83 $ 1.37 $ 3.72
============ =========== =========== ============
Diluted:
Net Earnings Applicable to Common Stock
Used in Basic Calculation........................... $17,650 $32,628 $53,463 $ 145,484
============ =========== =========== ============
Average Number of Common Shares Outstanding........... 39,118 39,118 39,118 39,118
Diluted Effect of Common Stock Equivalents (a)........ 207 630 366 653
------------ ----------- ----------- ------------
Average Common and Common Equivalent Shares
Outstanding......................................... 39,325 39,748 39,484 39,771
============ =========== =========== ============
Net Earnings per Share of Common Stock (Diluted)...... $ 0.45 $ 0.82 $ 1.35 $ 3.66
============ =========== =========== ============
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out-of-the-money options of 1,881,588 and 718,745 for the three
and nine months ended September 30, 2002, respectively. There were no
anti-dilutive common stock equivalents in 2001.
(7) 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 over the next five
years depending on market conditions. PNM has expended $208.8 million as of
September 30, 2002, of which $131.5 million was for equipment purchases. In
November 2001, PNM broke ground to build Afton Generating Station ("Afton"), a
135 MW simple 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 southwestern New Mexico. On June 27, 2002,
Lordsburg became fully operational and will serve the wholesale power market.
24
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. These plants were not built to serve New Mexico
retail customers and therefore will not be included in the rate base. However,
it is possible that these plants may be needed in the future to serve the
growing retail load. If so, these plants will have to be certified by the PRC
and would then be included in the rate base.
Terrorism Insurance
As of October 1, 2002, the Company's non-nuclear property insurance
contains a limitation on damage caused by terrorism. Terrorism coverage is
subject to specific coverage provisions and the amount recoverable is limited to
$5.0 million. Terrorism coverage for nuclear property and the Company's excess
liability insurance has also changed. The nuclear property and excess liability
changes are not considered material.
PVNGS Liability and Insurance Matters
The PVNGS participants have financial protection 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, PNM 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 PNM's 10.2% interest in the three PVNGS units, PNM'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 the payment of public liability claims in case of a
catastrophic accident involving a nuclear power plant, were up for renewal in
August 2002. While existing nuclear power plants 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. The U.S. House of
Representatives (the "House") passed a renewal bill 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 U.S. Senate (the "Senate") approved
a Price-Anderson Act amendment as a part of the comprehensive energy bill
("S.517"). House and Senate negotiators reached a compromise September 12, 2002.
Price-Anderson Act reauthorization is now part of a comprehensive energy bill
("H.R.4"). Both the current law and the versions approved by the House and
Senate provide for the primary financial protection limit to be the maximum
amount available from private insurance sources. Those sources are currently
being evaluated as to whether the $200 million now available for liability
claims per reactor could be increased to keep pace with inflation. The terms in
25
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
H.R.4 for the Price-Anderson Act amendment would reauthorize for 15 years,
increase the maximum assessment per reactor to approximately $99 million and
change the annual limit from $10 million to $15 million. The retroactive
assessments would be indexed to inflation. H.R.4 will not become law until the
balance of the bill is finalized by the conferees, approved by both the House
and Senate, and signed by the President. The Company cannot predict whether or
not the U.S. Congress will renew the Price-Anderson Act or whether or not an
increase will be made to the primary financial protection layer. In the event
the comprehensive energy bill does not pass, it is possible that the
Price-Anderson Act amendment would be passed as a stand-alone bill. However, 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 damage to, and decontamination of, property at PVNGS in the
aggregate amount of $2.75 billion as of October 1, 2002, a substantial portion
of which must be applied to stabilization and decontamination. PNM 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. PNM is a member of an industry mutual insurer. This mutual insurer
provides both the "all-risk" and increased cost of generation insurance to PNM.
In the event of adverse losses experienced by this insurer, PNM is subject to an
assessment. PNM's maximum share of any assessment is approximately $5.1 million
per year.
PVNGS Decommissioning Funding
PNM 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 2001 decommissioning cost study indicated that PNM's share of the PVNGS
decommissioning costs, excluding spent fuel disposal, would be approximately
$201 million (2001 dollars). The estimated market value of the trusts at the end
of September 30, 2002 was approximately $51.2 million.
PNM did not provide any additional funding for the nine months ended
September 30, 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, the DOE
was to develop the facilities necessary for the storage and disposal of spent
nuclear fuel and to have the first facility in operation by 1998. DOE has
announced that such a repository now cannot be completed before 2010.
26
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 until Fall 2003. The operator of
PVNGS believes it could augment that storage with the new facilities for on-site
dry storage of spent fuel for an indeterminate period of operation beyond 2003,
subject to obtaining any required governmental approvals. PNM currently
estimates that it will incur approximately $41.0 million (in 2001 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 that 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 2003.
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 PNM line near the
location. The explosion destroyed a small building and injured two persons who
were working in the building. PNM's investigation indicates that the leak was an
isolated incident likely caused by a combination of corrosion and increased
pressure. PNM also is cooperating with an investigation of the incident by the
PRC's Pipeline Safety Bureau (the "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 PNM
by the injured persons along with several claims for property and business
interruption damages have been resolved. The Company believes that the final
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 Westar Energy, Inc. (formerly known
as Western Resources) ("Westar Energy") announced that both companies' boards of
directors approved an agreement under which the Company would acquire the Westar
Energy electric utility operations in a tax-free, stock-for-stock transaction.
The agreement required that Westar Energy split-off its non-utility businesses
to its shareholders prior to closing.
After adverse rulings by the Kansas Corporation Commission regarding the
proposed split-off pursuant to the agreement and regarding Westar Energy's
electric rates, the transaction was terminated. The Company sued Westar Energy
in New York state court for unspecified damages for breach of contract and for
declaratory judgment. Westar Energy countersued, claiming entitlement to
termination fees in the amount of $25 million, plus costs and fees, and other
unspecified damages.
27
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On September 25, 2002, the Company and Westar Energy jointly announced
that they had settled the litigation, with each party dismissing its claims
against the other party and each party bearing its own costs.
Other
There are various claims and lawsuits pending against the Company. 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 its 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.
(8) 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 such reasonably
likely range of costs (classified as other long-term liabilities at undiscounted
amounts).
The Company's recorded minimum liability estimated to remediate its
identified sites is $8.5 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.
28
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For the nine months ended September 30, 2002 and 2001, the Company spent
$0.7 million and $2.2 million, respectively, for remediation. The majority of
the September 30, 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.
(9) Company Realignment
On August 22, 2002, the Company was realigned due to the changes in the
gas and electric industry and particularly, the negative impact on the Company's
earnings and growth prospects from wholesale market uncertainty. The changes
included consolidation of similar functions. A total of 85 salaried and hourly
employees were notified of their termination as part of the realignment. In
accordance with EITF 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity", the Company incurred
a liability of $8.8 million for severance and other related costs associated
with the involuntary termination of employees, which was charged to operations
in the quarter ended September 30, 2002.
(10) 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 results from
the acquisition, construction or development or the normal operation of a
long-lived asset. The asset retirement obligation must be recognized at its fair
value when incurred. The cost of the asset retirement obligation will 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
financial condition or results of operations 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 financial condition or results of operations.
29
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Statement of Financial Accounting Standards No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"). In April 2002, the FASB issued SFAS 145. This
statement updates and clarifies existing accounting pronouncements for treatment
of gains and losses from extinguishment of debt and eliminates an inconsistency
between required accounting for sale-leaseback transactions and the required
accounting for certain lease modifications that have similar economic effects as
sale-leaseback transactions. In accordance with previous accounting standards,
gains and losses from extinguishment of debt were classified as extraordinary
gains and losses. The current statement permits gains and losses from
extinguishment of debt to be classified as ordinary and included in income from
operations, unless they are unusual in nature or occur infrequently and are
therefore classified as an extraordinary item.
Emerging Issues Task Force ("EITF") Issue 02-3 "Issues Related to
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities", EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" and Statement of Financial Accounting
Standards No. 133 ("SFAS 133") "Accounting for Derivative Instruments and
Hedging Activities". The Company evaluates its energy contracts to determine if
they meet the definition of a derivative and are therefore subject to the
accounting requirements of SFAS 133. If an energy contract is determined not to
be a derivative under SFAS 133, it is then evaluated under EITF 98-10 to
determine whether it meets the definition of a trading activity and should be
marked to market with gains and losses recognized in earnings and separately
disclosed in the financial statements. EITF 98-10 allowed a gross or net
presentation of these gains and losses in the statement of earnings. In June
2002, the EITF reached a consensus in EITF 02-3 that all energy trading
activities must be presented on a net margin basis rather than a gross basis in
the statement of earnings and further required that all prior periods be
reclassified to conform to the current period presentation. On October 25, 2002,
the EITF reached a consensus to rescind EITF 98-10 and will no longer allow
energy contracts that do not meet the definition of a derivative under SFAS 133
to be marked to market and recognized in current earnings. As a result, all
contracts which were marked to market under EITF 98-10 and must now be accounted
for under the accrual method will be written back to cost with any difference
included as a cumulative effect adjustment in the period of adoption. This
transition provision will be effective for the first quarter of 2003. The
disclosure provisions previously agreed to in EITF 02-3 have also been
rescinded. In addition, any contracts within Statement 133 that are trading or
held for trading and are settled physically should be reported on a net basis.
Any contracts within Statement 133 that are not considered trading and are
settled physically should be reported on a gross basis. The EITF has directed
the FASB staff to provide a definition of trading activities to be included in
the final written consensus of EITF 02-3. The decision to rescind EITF 98-10,
the uncertainty as to the ultimate definition of trading activities and the
October 2002 consensus as to the effective date for adoption of EITF 02-3 has
nullified the June 2002 consensus on net margin versus gross basis presentation.
Therefore, the Company has not reclassified its energy trading activities to a
net margin presentation as of September 30, 2002 and is currently assessing the
impact of the EITF's October consensus on the accounting for its energy contract
portfolio. The Company expects to adopt EITF 02-3 in its entirety in the first
quarter of 2003.
30
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The SEC has indicated that financial statement reclassifications related
to periods previously audited by Arthur Andersen LLP ("Arthur Andersen") may
require the successor auditor to audit the prior periods and issue a new audit
report. Arthur Andersen audited the Company's financial statements for the
fiscal years 2001 and 2000. The successor auditor, Deloitte and Touche, has not
issued a new review report for the three and nine months ended September 30,
2001. However, Deloitte and Touche will perform an audit of the Companies'
financial statements for fiscal year 2001.
(11) Subsequent Events
New Long-Term Power Contract
On October 21, 2002, PNM entered into an agreement with FPL Energy LLC
("FPL"), a subsidiary of FPL Group, Inc., to develop a 200 MW wind generation
facility in New Mexico.
FPL Energy will build, own and operate the New Mexico Wind Energy Center
("NMWE"), consisting of 136 wind-powered turbines on a site in eastern New
Mexico. PNM will buy all the power generated by the NMWE under a 25-year
contract. Construction of the wind energy site is expected to begin later this
year. Construction on a facility of this size typically takes six to nine months
to complete.
PNM will ask the PRC to approve a voluntary tariff that will allow PNM
retail customers to buy wind-generated electricity for a small monthly premium.
Power from the facility not subscribed by PNM jurisdictional customers under the
voluntary program will be sold on the wholesale market, either within New Mexico
or outside of the state.
Electric Rate Agreement
In November 2001, PNM began settlement negotiations with the PRC utility
staff and intervenors in order to resolve its merchant plant filing and other
matters. Discussions included the future framework for restructuring the
electric industry in New Mexico under the Restructuring Act, a future retail
electric rate path and PNM's merchant plant filing.
The year-long negotiations ended on October 10, 2002, with the filing of
an agreement ("Agreement") with the PRC. If implemented, the Agreement will set
a rate path through 2007 and will resolve the issues surrounding industry
deregulation in New Mexico and the Company's merchant power strategy. The
Agreement was signed by PNM, the PRC Staff, the New Mexico Attorney General's
Office, the New Mexico Industrial Energy Consumers, the City of Albuquerque, and
the University of New Mexico. The United States Executive Agencies ("USEA")
initially filed a statement objecting to the Agreement, but on October 30, 2002
withdrew their objections and agreed to support the Agreement as if they had
signed it. The Agreement must be approved by the PRC and also provides for the
signatories to support passage of certain legislation in the New Mexico
Legislature. The parties to the Agreement have proposed that the PRC approve the
Agreement before the end of the year. The PRC hearing examiner has not yet set a
hearing date, but has scheduled a working session and pre-hearing conference for
November 19, 2002.
31
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Under the Agreement, PNM would decrease retail electric rates 6.5% in two
phases over the next three years. The first phase would be a 4.0% decrease,
effective September 2003. The second phase would be a further 2.5% decrease from
current rate levels, effective in September 2005. Rates would then be frozen at
that level until the end of 2007. These new rates would place PNM's rates as the
sixth lowest in the Southwest and among the lower half of utilities nationwide.
The Company expects to achieve necessary cost savings through additional cost
efficiencies. The risks and benefits of all off-system sales, other than the
dollar amounts of those already embedded in the stipulated rates, inure solely
to the Company's shareholders until December 2007. Since the new rate Agreement
does not provide for a fuel cost adjustment, the lower fuel costs sought to be
captured by shifting to underground mining for the coal supplies at San Juan
Generating Station ("SJGS") will flow through to the Company's earnings, largely
offsetting the reduction in retail revenues.
PNM would be able to seek a general rate adjustment during the rate
freeze period, if complying with any new or changed environmental or tax law or
regulation, or a new broader application of existing environmental or tax laws
or regulations, would compromise its financial integrity. PNM also would be
permitted to capitalize all the reasonable costs of mandatory renewable energy
resources, including an after-tax cost of capital of 8.64% to be recorded
concurrently with the deferral of those costs.
PNM would be authorized to recover in the stipulated rates and future
retail rates, its New Mexico jurisdictional share of the decommissioning costs
associated with the San Juan, La Plata and Navajo Surface Coal Mines. PNM would
be allowed to recover up to $100 million of the costs, composed of approximately
$69 million in surface coal mine reclamation costs, and approximately $31
million of contract buyout costs. The costs would be amortized over 17 years
commencing September 1, 2003 and in equal amounts each year after 2004. PNM
would not seek to recover a return on the unamortized reclamation costs, but
could seek to recover a return on the unamortized contract buyout costs
remaining as of December 31, 2007 in future rate adjustment proceedings.
The stipulated rates would also provide for full recovery of nuclear
decommissioning costs accrued in accordance with the estimates in the applicable
decommissioning cost study during the rate freeze period for PNM's interests in
PVNGS Units 1 and 2. The portion of SJGS Unit 4 previously treated as an
excluded resource from PNM's New Mexico retail rates would be included as a
generation resource to serve PNM's New Mexico retail and wholesale firm
requirements customers' load. PNM's contracts to purchase power from Tri-State
Generation and Transmission Association, Inc., Delta Person Limited Partnership
and firm power from Southwestern Public Service Company would also be included
as generation resources to serve PNM's New Mexico retail and wholesale firm
requirements customers' load until each contract expires under the Agreement.
32
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
PRC approval or other authorization from the PRC would not be required
for PNM's merchant plant investment as long as PNM meets the following
conditions: (a) PNM does not invest more than $1.25 billion in merchant plant;
(b) PNM has an investment grade credit rating on a stand alone basis and on a
consolidated basis with PNM Resources; and (c) PNM spends at least $60 million
per year in gas and electric utility, non-merchant plant infrastructure needed
to maintain adequate and reliable service. No prior approval for merchant plant
participation would be required and expedited PRC approval would be available
for financing of merchant plant if certain specified financial conditions are
met. If PNM's credit rating on a stand alone or consolidated basis with the
Holding Company falls below investment grade, however, approvals are needed for
new merchant plant projects and for continuing to participate in merchant plant
projects of more than certain dollar value and under certain conditions.
PRC approval would not be required for PNM to transfer any part of its
interests in merchant plant or PVNGS Unit 3 from time to time to any other legal
entity, provided that the following conditions are met: (a) PNM's debt to
capital ratio will not exceed 65% after giving effect to the transfer and (b)
PNM's investment grade status on a stand-alone basis and on a consolidated basis
with the Holding Company will not be impaired by the transfer of merchant plant
or PVNGS Unit 3 at the time of transfer.
PNM further agreed in the Agreement that it will transfer all its
interests in merchant plant out of PNM by January 1, 2010. PNM will accelerate
the mandatory transfer to a date one year after PNM has completed expenditures
of $1.25 billion on merchant plant. PNM may seek a variance from the PRC at any
time prior to January 1, 2010 to extend or vacate the time or terms and
conditions requiring the transfer but not beyond January 1, 2015.
Under the Agreement, if merchant plant or PVNGS Unit 3 is transferred to
a PNM affiliate, PNM's generation resources and the affiliate's generation
resources may be jointly dispatched at the merchant affiliate's sole discretion
until January 1, 2015. Joint dispatch of all utility, PVNGS Unit 3 or merchant
plant resources would be terminable at any time between 2008 and 2015 at PNM's
discretion, as long as the utility's dispatch capability is not impaired in any
way.
PNM agreed to forego its pursuit to recover the costs incurred in
preparing to transition to a competitive retail market in New Mexico. This will
result in a one-time write off of approximately $16.7 million, pre-tax, upon
approval by the PRC of the Agreement.
In the Agreement, PNM, PRC utility staff and intervenors agree to
actively support the repeal of most of the Restructuring Act of 1999. If the
repeal does not occur during the 2003 New Mexico Legislative Session, various
modifications to the conditions of the Agreement are triggered depending on how
long repeal is delayed.
The Company is currently unable to predict the impact these proceedings
may have on its plans to expand its generating capacity and its future financial
condition and results of operations.
33
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. ("Holding Company") and
Subsidiaries and Public Service Company of New Mexico ("PNM") (collectively the
"Company") is presented on a combined basis. The 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 the Holding Company pursuant to
an order from the New Mexico Public Regulation Commission ("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 PNM Resources, Inc. and
Subsidiaries 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 PNM Resources, Inc.
and Subsidiaries under 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 considered material to the Company
are discussed to the extent known.
OVERVIEW
PNM Resources, Inc., 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.
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Holding Company, the Holding Company became the parent
company of PNM. Prior to the share exchange, the Holding Company had existed as
a subsidiary of PNM. The new parent company began trading on the New York Stock
Exchange under the same PNM symbol beginning on December 31, 2001.
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, PNM has an
obligation to serve its customers under the jurisdiction of the PRC. As a
merchant, PNM markets excess production from the utility, as well as unregulated
generation, into a competitive market place. The Company also has an electric
power trading area focused on purchasing wholesale electricity in the market for
future resale or to provide energy to jurisdictional customers in New Mexico
when the Company's generation assets cannot satisfy demand. The marketing and
trading operations utilize an asset-backed trading strategy, whereby the
Company's aggregate net open position for the sale of electricity is covered by
34
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.
As it currently operates, 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 due to its immateriality and is combined with the
distribution business line for disclosure purposes.
The Electric and Gas Services strategy is directed at supplying
reasonably priced and reliable energy to retail customers through
customer-driven operational excellence, high quality customer service, cost
efficient 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, balanced with
stringent risk management policies. The Company's future growth plans call for
approximately 75% of its new generation portfolio to be committed through
long-term contracts, including its sales to retail customers. Growth will be
dependent on market development, and upon the Company's ability to generate
funds for the Company's future expansion. Although the current environment has
led the Company to scale back its expansion plans, the Company will continue to
operate in the wholesale market. Expansion of the Company's generating portfolio
will depend upon acquiring favorably priced assets at strategic locations and
securing long-term commitments for the purchase of power from the acquired
plants.
35
RESULTS OF OPERATIONS
Three Months Ended September 30, 2002
Compared to Three Months Ended September 30, 2001
Consolidated
The Company's net earnings available to common shareholders for the three
months ended September 30, 2002 were $17.7 million, a 45.9% decrease in net
earnings from $32.6 million the three months ended September 30, 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.
Earnings for the third quarter 2002 and 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
September 30,
-----------------------------------------------------
2002 2001
------------------------- --------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
------------ ------------ ------------- ------------
Net Earnings Available for Common
Shareholders................................ $17,650 $ 0.45 $32,628 $ 0.82
------------ ------------ ------------- ------------
Adjustment for Special Gains and Charges
(net of income tax effects):
Realignment costs............................ (5,337) 0.14 - -
Write-off of an Avistar investment........... - - (2,519) (0.06)
Western Resources acquisition costs.......... - - (3,061) (0.08)
------------ ------------ ------------- ------------
Total...................................... (5,337) 0.14 (5,580) (0.14)
------------ ------------ ------------- ------------
Net Earnings Available For Common-
Shareholders Excluding Special Gains
And Charges................................. $22,987 $ 0.59 $38,208 $ 0.96
============ ============ ============ ============
To adjust reported net earnings and diluted earnings per share to exclude
the non-recurring charges, such charges, net of income tax benefit, are added
back to reported net earnings under GAAP.
36
The following discussion is based on the financial information presented
in the Consolidated Financial Statements - Segment Information note in the Notes
to Consolidated Financial Statements.
Utility Operations
Electric
The table below sets forth the operating results for the Electric
business segment.
Electric
Three Months Ended
September 30,
---------------------------
2002 2001 Variance
------------ ------------ ------------
In thousands)
Operating revenues:
External customers....................... $156,363 $153,535 $ 2,828
Intersegment revenues.................... 177 177 -
------------ ------------ ------------
Total revenues........................... 156,540 153,712 2,828
------------ ------------ ------------
Cost of energy sold........................ 842 1,146 (304)
Intersegment purchases..................... 96,592 95,413 1,179
------------ ------------ ------------
Total cost of energy..................... 97,434 96,559 875
------------ ------------ ------------
Gross margin............................... 59,106 57,153 1,953
------------ ------------ ------------
Administrative and other................... 13,235 11,035 2,200
Depreciation and amortization.............. 8,338 8,219 119
Transmission and distribution costs........ 8,547 10,179 (1,632)
Taxes other than income taxes.............. 3,004 2,867 137
Income taxes............................... 7,887 7,618 269
------------ ------------ ------------
Total non-fuel operating expenses........ 41,011 39,918 1,093
------------ ----------- ------------
Operating income........................... $ 18,095 $ 17,235 $ 860
------------ ------------ ------------
Operating revenues increased $2.8 million or 1.8% for the period to
$156.5 million. Retail electricity delivery grew 1.2% to 2.05 million MWh in
2002 compared to 2.03 million MWh delivered in the prior year period, resulting
in increased revenues of $4.7 million period-over-period. This volume increase
was the result of a weather-driven increase in consumption and continued load
growth of 1.2%, which is consistent with historical levels. This increase in
revenues was partially offset by a decrease in transmission revenues of $2.1
million due to the slowdown in the wholesale market.
(Intentionally left blank)
37
The following table shows electric revenues by customer class and average
customers:
Electric Revenues
(In thousands)
Three Months Ended
September 30,
2002 2001
------------ ------------
Residential.......................... $53,213 $49,942
Commercial........................... 69,800 68,422
Industrial........................... 21,819 21,836
Other................................ 11,708 13,512
------------ ------------
$156,540 $153,712
============ ============
Average customers.................... 385,468 378,336
============ ============
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
Three Months Ended
September 30,
2002 2001
------------ ------------
Residential.......................... 620,299 593,186
Commercial........................... 928,251 932,204
Industrial........................... 427,481 425,299
Other................................ 74,225 75,750
------------ ------------
2,050,256 2,026,439
============ ============
The gross margin, or operating revenues minus cost of energy sold,
increased $2.0 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.
Total non-fuel operating expenses increased $1.1 million or 2.7%.
Administrative and other increased $2.2 million or 19.9% due to higher
administrative costs allocated from Corporate. Transmission and distribution
costs decreased $1.6 million or 16.0% primarily due to maintenance performed in
2001 to improve system reliability, which did not recur in 2002.
38
Gas
The table below sets forth the operating results for the Gas business
segment.
Gas
Three Months Ended
September 30,
----------------------------
2002 2001 Variance
------------- ------------- -------------
(In thousands)
Operating revenues:
External customers........................ $ 36,244 $ 39,649 $ (3,405)
Intersegment revenues..................... 666 - 666
------------- ------------- -------------
Total operating revenues.................... 36,910 39,649 (2,739)
Total cost of energy........................ 12,905 14,329 (1,424)
------------- ------------- -------------
Gross margin................................ 24,005 25,320 (1,315)
------------- ------------- -------------
Administrative and other.................... 13,490 12,270 1,220
Depreciation and amortization............... 5,160 5,400 (240)
Transmission and distribution costs......... 7,312 8,126 (814)
Taxes other than income taxes............... 1,899 1,338 561
Income taxes................................ (2,910) (1,676) (1,234)
------------- ------------- -------------
Total non-fuel operating expenses......... 24,951 25,458 (507)
------------- ------------- -------------
Operating loss.............................. $ (946) $ (138) $ (808)
------------- ------------- -------------
Operating revenues decreased $2.7 million or 6.9% for the period to $36.9
million, primarily as a result of lower natural gas prices during the third
quarter of 2002 as compared to the same period in the previous year and a
decrease in gas sales volumes of 14.4%, largely from fewer purchases from
Generation and Trading to support gas-fired generation. 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.
The following table shows gas revenues by customer and average customers:
Gas Revenues
(In thousands)
Three Months Ended
September 30,
2002 2001
------------ ------------
Residential...................... $20,550 $21,717
Commercial....................... 6,248 6,700
Industrial....................... 348 623
Transportation*.................. 4,941 6,024
Other............................ 4,823 4,585
------------ ------------
$ 36,910 $39,649
============ ============
Average customers................ 439,637 431,703
============ ============
39
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
Three Months Ended
September 30,
2002 2001
------------ ------------
Residential.................. 2,291 2,337
Commercial................... 1,262 1,176
Industrial................... 94 145
Transportation*.............. 13,753 16,842
Other........................ 801 764
------------ ------------
18,201 21,264
============ ============
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold,
decreased $1.3 million or 5.2%. This decrease is due mainly to lower consumption
of gas for electric generation. The Company currently believes that gas assets
are not earning an adequate level of return. As a result, the Company
anticipates filing a request for increased rates by year-end 2002. The Company's
last gas rate case filing was in October 1997.
Total non-fuel operating expense decreased $0.5 million or 2.0%.
Administrative and other costs increased $1.2 million or 9.9% for the period
primarily due to higher administrative costs allocated from Corporate. The
increase in the Corporate allocation was partially offset by a decrease in bad
debt expense resulting from improved collection levels. Transmission and
distribution costs decreased $0.8 million due to maintenance performed in 2001
to improve system reliability, which did not recur in 2002. Taxes other than
income increased $0.5 million or 41.9% due to the absence of favorable audit
outcomes by certain tax authorities recognized in 2001. Income taxes, which
include taxes for interest charges, decreased $1.2 million or 73.6%, due to the
decline in pre-tax income.
(Intentionally left blank)
40
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
September 30,
----------------------------
2002 2001 Variance
------------- ------------- --------------
(In thousands)
Operating revenues:
External customers..................... $ 96,497 $428,531 $(332,034)
Intersegment revenues.................. 96,592 95,413 1,179
------------- ------------- --------------
Total revenues......................... 193,089 523,944 (330,855)
------------- ------------- --------------
Cost of energy sold...................... 118,851 414,489 (295,638)
Intersegment purchases................... 843 177 666
------------- ------------- --------------
Total cost of energy................... 119,694 414,666 (294,972)
------------- ------------- --------------
Gross margin............................. 73,395 109,278 (35,883)
------------- ------------- --------------
Administrative and other................. 9,605 10,397 (792)
Energy production costs.................. 34,534 35,547 (1,013)
Depreciation and amortization............ 11,107 10,565 542
Taxes other than income taxes............ 2,628 2,368 260
Income taxes............................. 4,289 18,184 (13,895)
------------- ------------- --------------
Total non-fuel operating expenses...... 62,163 77,061 (14,898)
------------- ------------- --------------
Operating income......................... $ 11,232 $ 32,217 $ (20,985)
------------- ------------- --------------
Operating revenues declined $330.9 million or 63.1% for the period to
$193.1 million. This decrease in wholesale electricity sales primarily reflects
the slowdown in the wholesale electric market that resulted from steep declines
in wholesale prices and trading activity as compared to the prior year.
The significantly higher wholesale pricing in 2001 was driven by
increased demand in California, a lack of generating assets to serve the market,
and the impact of warm weather. By contrast, 2002 has seen relatively mild
weather in the West, an abundance of low cost hydropower and weak economic
conditions in the region. As a result, average prices in the third quarter were
approximately $35 per MWh as opposed to $123 per MWh in the prior year quarter.
Trading volume declines reflect the reduction in trading partners in the
wholesale market caused by bankruptcy, reduced credit quality of firms in the
market, and firms exiting the wholesale trading market. There are also
significant unresolved legal, political and regulatory issues that had a
dampening effect on activity in the marketplace. As a result, the Company's spot
market and short-term sales have declined significantly. The Company delivered
wholesale (bulk) power of 2.5 million MWh of electricity for the three months
ended September 30, 2002, compared to 3.5 million MWh for the same period in
2001.
Although other firms have exited the wholesale market or have had their
access to the wholesale market limited due to concerns over credit quality, the
Company remains committed to be a participant in this market place. While market
liquidity is weak, the Company will focus on long-term relationships with
smaller wholesale customers (small investor-owned utilities, municipal utilities
and co-ops). At the same time, the Company will continue to monitor market
conditions. This commitment to the wholesale market leaves the Company poised to
participate in the market as liquidity returns and regulatory issues are
resolved.
41
The following table shows revenues by customer class:
Generation and Trading Revenues By Market
(In thousands)
Three Months Ended
September 30,
2002 2001
--------------- -------------
Intersegment sales.............. $ 96,592 $ 95,413
Long-term contract.............. 7,261 15,967
Trading*........................ 83,828 412,564
Other........................... 5,408 -
--------------- -------------
$ 193,089 $ 523,944
=============== =============
*Includes settled trading contracts and mark-to-market gains/(losses).
The following table shows sales by customer class:
Generation and Trading Sales By Market
(Megawatt hours)
Three Months Ended
September 30,
2002 2001
--------------- -------------
Intersegment sales................ 2,050,256 2,026,439
Long-term contract................ 160,946 322,930
Trading........................... 2,306,314 3,194,083
--------------- -------------
4,517,516 5,543,452
=============== =============
The gross margin, or operating revenues minus cost of energy sold,
decreased $35.9 million or 32.8%. Lower margins were created primarily by weak
pricing, less price volatility and decreased trading activity. Margins were also
impacted by higher coal costs at the San Juan Generating Station ("SJGS"). The
Company's previously announced transition to an underground mine for the supply
of coal at SJGS was delayed, necessitating the continuation of the more
expensive surface mine operation. These lower margins were partially offset by a
favorable change in the mark-to-market position of the trading portfolio of $6.6
million period-over-period ($6.0 million gain in 2002 versus a $0.6 million loss
in 2001). A portion of the gain in 2002 represents the reversal of previously
recognized mark-to-market losses.
Non-fuel operating expenses decreased $14.9 million or 19.3%.
Administrative and other costs decreased $0.8 million or 7.6% due to a decline
in power marketing expenses resulting from the slowdown in the wholesale power
market and lower costs resulting from increased capital activity for generation
expansion. These decreases were partially offset by higher administrative costs
allocated from Corporate. Energy production costs decreased $1.0 million or 2.8%
for the period primarily due to lower maintenance costs as a result of an outage
42
at SJGS in 2001 that did not recur in 2002. This decrease was partially offset
by higher costs at PVNGS due to a planned outage and costs at PNM's Lordsburg
plant, which became fully operational in June 2002. Depreciation and
amortization increased $0.5 million due to the addition of Lordsburg. Income
taxes, which include taxes for interest charges, decreased $13.9 million or
76.4%, due to the decline in pre-tax income.
Corporate
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, increased $1.8 million for
the period to $23.3 million. This increase was primarily due to severance costs
resulting from a realignment of the Company's business structure (the
"Realignment") and higher labor resulting from a transfer of employees from
operations to Corporate. In accordance with EITF 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
("EITF 94-3")," the Company incurred a liability of $8.8 million for severance
and other related costs associated with the involuntary termination of
employees. As of November 1, 2002, $5.1 million of severance-related benefits
were paid and charged against the liability. This increase was partially offset
by lower bonus expense resulting from lower earnings projections and lower costs
resulting from the reduction of certain unregulated activities.
Other Non-Operating
Other deductions decreased $4.2 million or 44.6% primarily due to charges
in 2001 that did not recur in 2002. In 2001, the Company recognized charges for
the write-off of an Avistar investment and certain costs related to the
Company's now terminated acquisition of Western Resources' electric utility
operations.
Income Taxes
The Company's consolidated income tax expense was $7.4 million for the
three months ended September 30, 2002, compared to $22.3 million for the three
months ended September 30, 2001. The impact of lower earnings in 2002
contributed to the difference. The Company's effective income tax rates for the
three months ended September 30, 2002 and 2001 were 29.23% and 40.54%,
respectively. Included in the Company's 2001 taxable income were certain
non-deductible costs related to the Company's now terminated acquisition of
Western Resources' electric utility operations. Excluding these costs, the
Company's effective tax rate was 38.76% in 2001. The decrease in the effective
rate quarter over quarter was due to the reduction in earnings in 2002 without a
corresponding reduction in permanent tax benefits and to the recognition of
certain research and development credits.
43
RESULTS OF OPERATIONS
Nine Months Ended September 30, 2002
Compared to Nine Months Ended September 30, 2001
Consolidated
The Company's net earnings available to common shareholders for the nine
months ended September 30, 2002 were $53.5 million, a 63.1% decrease in net
earnings from $145.5 million in 2001. This decrease primarily reflects the
slowdown in the wholesale electric market, where both prices and trading
activity were significantly lower than the prior year period. Despite the
slowdown in the wholesale electric market, PNM's electric utility operations
recorded operating income growth of 3.5%. 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.
Nine Months Ended
September 30,
--------------------------------------------------------
2002 2001
-------------------------- ----------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
------------- ------------ -------------- -------------
Net Earnings Available for Common
Shareholders................................. $53,463 $ 1.35 $ 145,484 $ 3.66
------------- ------------ -------------- -------------
Adjustment for Special Gains and Charges
(net of income tax effects):
Realignment costs............................ (5,337) (0.14) - -
Contribution to PNM Foundation................ - - (3,021) (0.07)
Write-off of non-recoverable coal mine
decommissioning costs...................... - - (7,840) (0.20)
Write-off of an Avistar investment............ - - (7,907) (0.20)
Western Resources acquisition costs........... - - (4,832) (0.18)
------------- ------------ -------------- -------------
Total....................................... (5,337) (0.14) (23,600) (0.65)
------------- ------------ -------------- -------------
Net Earnings Available For Common-
Shareholders Excluding Special Gains
and Charges.................................. $58,800 $ 1.49 $ 169,084 $ 4.31
============= ============ ============= =============
To adjust reported net earnings and diluted earnings per share to exclude
the non-recurring charges, such charges, net of income tax benefit, are added
back to reported net earnings under GAAP.
44
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
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance
-------------- -------------- -------------
(In thousands)
Operating revenues:
External customers....................... $431,929 $424,249 $ 7,680
Intersegment revenues.................... 530 530 -
-------------- -------------- -------------
Total revenues........................... 432,459 424,779 7,680
-------------- -------------- -------------
Cost of energy sold........................ 3,054 3,958 (904)
Intersegment purchases..................... 264,554 259,726 4,828
-------------- -------------- -------------
Total cost of energy..................... 267,608 263,684 3,924
-------------- -------------- -------------
Gross margin............................... 164,851 161,095 3,756
-------------- -------------- -------------
Administrative and other................... 38,383 35,975 2,408
Depreciation and amortization.............. 25,239 24,310 929
Transmission and distribution costs........ 25,864 26,619 (755)
Taxes other than income taxes.............. 9,382 8,527 855
Income taxes............................... 19,141 20,389 (1,248)
-------------- -------------- -------------
Total non-fuel operating expenses........ 118,009 115,820 2,189
-------------- -------------- -------------
Operating income........................... $ 46,842 $ 45,275 $ 1,567
-------------- -------------- -------------
Operating revenues increased $7.7 million or 1.8% for the period to
$432.5 million. Retail electricity delivery grew 1.8% to 5.62 million MWh in
2002 compared to 5.52 million MWh delivered in the prior year period, resulting
in increased revenues of $11.1 million year-over-year. This volume increase was
the result of a weather-driven increase in consumption and continued load growth
of 1.8%. Period over period, customer growth was 2.4%. This increase in revenues
was partially offset by a decrease in transmission revenues of $3.1 million due
to the slowdown in the wholesale market.
(Intentionally left blank)
45
The following table shows electric revenues by customer class and average
customers:
Electric Revenues
(In thousands)
Nine Months Ended
September 30,
2002 2001
------------- -------------
Residential..................... $149,631 $142,785
Commercial...................... 187,382 183,372
Industrial...................... 62,239 62,161
Other........................... 33,207 36,461
------------- -------------
$432,459 $424,779
============= =============
Average customers............... 383,572 376,520
============= =============
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
Nine Months Ended
September 30,
2002 2001
------------- -------------
Residential...................... 1,743,712 1,676,271
Commercial....................... 2,462,728 2,447,231
Industrial....................... 1,225,398 1,210,266
Other............................ 183,590 182,450
------------- -------------
5,615,428 5,516,218
============= =============
The gross margin, or operating revenues minus cost of energy sold,
increased $3.8 million or 2.3%, 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.
Total non-fuel operating expenses increased $2.2 million or 1.9%.
Administrative and other costs increased $2.4 million or 6.7% due to higher
administrative costs allocated from Corporate, partially offset by lower bad
debt expense as a result of collection improvements and the absence of losses
from the bankruptcy of a significant customer in 2001. Depreciation and
amortization increased $0.9 million or 3.8% for the period due to a higher
depreciable plant base. Transmission and distribution costs decreased $0.8
million or 2.8% primarily due to maintenance performed in 2001 to improve system
reliability, which did not recur in 2002. Taxes other than income increased $0.9
million or 10.0% primarily reflecting the absence of favorable audit outcomes by
certain tax authorities recognized in 2001. Income taxes, which include taxes
associated with interest charges, decreased $1.2 million or 6.1% due to lower
pre-tax income.
46
Gas
The table below sets forth the operating results for the Gas business
segment.
Gas
Nine Months Ended September 30,
---------------------------------
2002 2001 Variance
-------------- --------------- --------------
(In thousands)
Operating revenues:
External customers....................... $ 189,413 $ 318,670 $ (129,257)
Intersegment revenues.................... 1,136 - 1,136
-------------- --------------- --------------
Total revenues............................. 190,549 318,670 (128,121)
Total cost of energy....................... 96,576 220,547 (123,971)
-------------- --------------- --------------
Gross margin............................... 93,973 98,123 (4,150)
-------------- --------------- --------------
Administrative and other................... 39,147 39,797 (650)
Depreciation and amortization.............. 15,548 16,023 (475)
Transmission and distribution costs........ 21,836 21,829 7
Taxes other than income taxes.............. 5,985 4,990 995
Income taxes............................... 526 2,819 (2,293)
-------------- --------------- --------------
Total non-fuel operating expenses........ 83,042 85,458 (2,416)
-------------- --------------- --------------
Operating income........................... $ 10,931 $ 12,665 $ (1,734)
-------------- --------------- --------------
Operating revenues decreased $128.1 million or 40.2% for the period to
$190.5 million, primarily as the result of lower natural gas prices in 2002 as
compared to 2001 and a decrease in gas sales volumes of 10.2%, largely resulting
from fewer purchases from Generation and Trading to support gas-fired
generation. Despite the volume decline, customer growth was approximately 2.1%.
PNM 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.
The following table shows gas revenues by customer and average customers:
Gas Revenues
(In thousands)
Nine Months Ended
September 30,
2002 2001
-------------- -------------
Residential.................... $118,274 $188,113
Commercial..................... 36,838 56,375
Industrial..................... 1,412 26,541
Transportation*................ 13,686 16,437
Other.......................... 20,339 31,204
-------------- -------------
$190,549 $318,670
============== =============
Average customers.............. 442,364 433,549
============== =============
47
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
Nine Months Ended
September 30,
2002 2001
-------------- -------------
Residential.................... 18,791 18,357
Commercial..................... 7,826 6,867
Industrial..................... 390 3,665
Transportation*................ 35,226 41,243
Other.......................... 3,905 3,541
-------------- -------------
66,138 73,673
============== =============
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold,
decreased $4.2 million or 4.2%. This decrease is due mainly to lower consumption
of gas for electric generation partially offset by a 2.0% growth in customer
base.
Total non-fuel operating expenses decreased $2.4 million or 2.8%.
Administrative and other costs decreased $0.7 million or 1.6%. This decrease is
primarily due to lower bad debt expense as a result of collection improvements
and the absence of losses from the bankruptcy of a significant customer in 2001.
This cost improvement was largely offset by higher allocated Corporate
administrative costs. Taxes other than income increased $1.0 million or 19.9%
due to the absence of favorable audit outcomes by certain tax authorities
recognized in 2001. Income taxes, which include income taxes for interest
charges, decreased $2.3 million or 81.3% due to lower pre-tax income.
(Intentionally left blank)
48
Generation and Trading Operations
The table below sets forth the operating results for the Generation and
Trading business segment.
Generation and Trading
Nine Months Ended September 30,
---------------------------------
2002 2001 Variance
--------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers....................... $245,411 $1,280,141 $(1,034,730)
Intersegment revenues.................... 264,554 259,726 4,828
--------------- --------------- ---------------
Total revenues........................... 509,965 1,539,867 (1,029,902)
--------------- --------------- ---------------
Cost of energy sold........................ 310,769 1,136,400 (825,631)
Intersegment purchases..................... 1,666 530 1,136
--------------- --------------- ---------------
Total cost of energy..................... 312,435 1,136,930 (824,495)
--------------- --------------- ---------------
Gross margin............................... 197,530 402,937 (205,407)
--------------- --------------- ---------------
Administrative and other................... 25,968 25,388 580
Energy production costs.................... 102,448 107,135 (4,687)
Depreciation and amortization.............. 32,587 31,981 606
Taxes other than income taxes.............. 8,244 6,611 1,633
Income taxes............................... 6,633 82,805 (76,172)
--------------- --------------- ---------------
Total non-fuel operating expenses........ 175,880 253,920 (78,040)
--------------- --------------- ---------------
Operating income........................... $ 21,650 $ 149,017 $ (127,367)
--------------- --------------- ---------------
Operating revenues declined $1.0 billion or 66.9% for the period to
$510.0 million. This decrease in wholesale electricity sales primarily reflects
the slowdown in the wholesale electric market, which resulted from steep
declines in wholesale prices and trading activity as compared to the prior year
period.
The significantly higher wholesale pricing in 2001 was driven by
increased demand in California, a lack of generating assets to serve the market,
and the impact of warm weather. By contrast, 2002 has seen relatively mild
weather in the West, an abundance of low cost hydropower and weak economic
conditions in the region. As a result, the average price realized by the Company
fell to approximately $29 per MWh in 2002 versus $133 per MWh in 2001.
Trading volume declines reflect the reduction in trading partners in the
wholesale market caused by bankruptcy, reduced credit quality of firms in the
market and firms exiting the wholesale trading market. There are also
significant unresolved legal, political and regulatory issues that had a
dampening effect on activity in the marketplace. As a result, the Company's spot
market and short-term sales have declined significantly. The Company delivered
wholesale (bulk) power of 7.2 million MWh of electricity for the nine months
ended September 30, 2002, compared to 9.8 million MWh for the same period in
2001.
Although other firms have exited the wholesale market or have had their
access to the wholesale market limited due to concerns over credit quality, the
Company remains committed to be a participant in this market place. While market
liquidity is weak, the Company will focus on long-term relationships with
smaller wholesale customers (small investor-owned utilities, municipal utilities
and co-ops). At the same time, the Company will continue to monitor market
conditions. This commitment to the wholesale market leaves the Company poised to
participate in the market as liquidity returns and regulatory issues are
resolved.
49
The following table shows revenues by customer class:
Generation and Trading Revenues By Market
(In thousands)
Nine Months Ended
September 30,
2002 2001
-------------- --------------
Intersegment sales................. $ 264,554 $ 259,726
Long-term contract................. 32,160 61,762
Trading*........................... 199,702 1,217,447
Other.............................. 13,549 932
-------------- --------------
$ 509,965 $1,539,867
============== ==============
*Includes settled trading contracts and mark-to-market gains/(losses).
The following table shows sales by customer class:
Generation and Trading Sales By Market
(Megawatt hours)
Nine Months Ended
September 30,
2002 2001
---------------- ---------------
Intersegment sales............... 5,615,428 5,516,218
Long-term contract............... 669,099 1,169,877
Trading.......................... 6,569,009 8,656,623
---------------- ---------------
12,853,536 15,342,718
================ ===============
The gross margin, or operating revenues minus cost of energy sold,
decreased $205.4 million or 51.0%. Lower margins were created primarily by weak
pricing, less price volatility and lower trading liquidity. Margins were also
impacted by higher coal costs at SJGS. The Company's previously announced
transition to an underground mine for supply of coal at SJGS was delayed,
necessitating the continuation of the more expensive surface mine operation.
These lower margins were partially offset by a favorable change in the
mark-to-market position of the trading portfolio of $48.9 million
period-over-period ($22.1 million gain in 2002 versus $26.8 million loss in
2001). A portion of the gain in 2002 represents the reversal of previously
recognized mark-to-market losses.
Total non-fuel operating expenses decreased $78.0 million or 30.7%.
Administrative and other costs increased $0.6 million or 2.3% for the period.
This increase is primarily due to higher corporate cost allocations, partially
offset by an adjustment to prior year SJGS participant billings (the Company is
the operator of SJGS and shares costs with other owners) and lower costs
resulting from increased capital activity for generation expansion. Energy
production costs decreased $4.7 million or 4.4% for the period reflecting the
benefits of the acceleration into 2001 of a planned outage at SJGS and an
adjustment to prior year PVNGS billings from Arizona Public Service Company the
50
operator of PVNGS. These cost decreases were partially offset by planned and
unplanned outages at PNM's Four Corners facility and costs at Lordsburg, which
became fully operational in June 2002. Depreciation and amortization increased
$0.6 million or 1.9% due to the addition of Lordsburg. Taxes other than income
increased $1.6 million or 24.7% reflecting adjustments recorded in the prior
year for favorable audit outcomes by certain tax authorities. Income taxes,
which include income taxes for interest charges, decreased $76.2 million or
92.0% due to a decline in pre-tax income.
Corporate
Corporate administrative and general costs, which represent costs that
are driven primarily by corporate-level activities, decreased $2.2 million for
the period to $68.9 million. This decrease was primarily due to lower retiree
benefits expense and lower bonus expense in the current year resulting from
lower earnings projections and lower costs resulting from the reduction of
certain unregulated activities. These decreases were partially offset by
severance costs resulting from the Realignment, higher legal costs due to
increased business exposures and outside services related to debt refinancing
activities. In accordance with EITF 94-3, the Company incurred a liability of
$8.8 million for severance and other related costs associated with the
involuntary termination of employees. As of November 1, 2002, $5.1 million of
severance-related benefits were paid and charged against the liability.
Other Non-Operating
Other income decreased by $4.8 million or 12.0% reflecting lower
year-over-year returns on investments reflecting market conditions.
Other deductions decreased $48.0 million or 88.6% primarily due to
charges in 2001 that did not recur in 2002. In 2001, the Company recognized
charges for the write-off of non-recoverable coal mine decommissioning costs, a
contribution to the PNM Foundation, the write-off of an Avistar investment, and
certain costs related to the Company's now terminated acquisition of Western
Resources' electric utility operations.
Income Taxes
The Company's consolidated income tax expense was $27.1 million for the
nine months ended September 30, 2002, compared to $85.9 million for the nine
months ended September 30, 2001. The impact of lower earnings in 2002
contributed to the difference. The Company's effective income tax rates for the
nine months ended September 30, 2002 and 2001 were 33.48% and 37.06%,
respectively. Included in the Company's 2001 taxable income were certain
non-deductible costs related to the Company's now terminated acquisition of
Western Resources' electric utility operations. In addition, the Company
determined that $6.6 million of allowances taken against certain income tax
related regulatory assets were no longer required due to changes in the
evaluation of its regulatory strategy in light of the Holding Company filing in
May 2001. In 2000, when the allowance was established, management believed these
income- tax-related regulatory assets would not be recoverable based on the
probable regulatory outcome of industry restructuring in New Mexico. Currently,
management fully expects to recover these costs in future rate cases, a
situation that was not possible prior to the delay of open access in New Mexico.
Excluding these costs, the Company's effective tax rate was 38.88% in 2001. The
decrease in the effective rate was due to the reduction in earnings in 2002
without a corresponding reduction in permanent tax benefits and the recognition
of certain research and development credits.
51
FUTURE EXPECTATIONS
On July 9, 2002, the Company announced that it expects 2002 earnings for
the twelve months to be in the range of $1.90 to $2.10. Although the Company's
electric utility continues to perform well, the depressed level of wholesale
prices in the West, coupled with the significantly decreased trading activity in
that market, has severely limited the potential of Generation and Trading.
Several factors, including an abundance of available hydropower from the
Pacific Northwest, cooler weather through May and June, low natural gas prices,
the number of new generating plants coming on line, and the lingering slowdown
in the regional economy have all contributed to keeping power prices down in
2002. Additionally, fewer credit-worthy counterparties and legal, political and
regulatory uncertainty regarding the Western marketplace have significantly
reduced market liquidity and trading volume as some companies have curtailed
their activity or exited the business altogether. These factors resulted in a
26.3% reduction in wholesale sales for the Company for the nine months ended
September 30, 2002 compared to the nine months ended September 30, 2001.
Other factors contributing to the year over year decrease in earnings
include increased coal costs and lower earnings in the gas utility business as a
result of a mild spring.
On October 10, 2002, the Company filed a rate agreement with the PRC,
which if approved, will set an electric utility rate path for the Company
through 2007 (see Merchant Plant Filing and Electric Rate Settlement). Under the
rate agreement, PNM will reduce its retail electric rates by 6.5% in two phases
over the next three years. The Company expects to realize certain cost savings,
primarily through lower coal fuel costs by switching to underground mining at
SJGS, largely offsetting the revenue reduction and allowing for an 10.5% rate of
return on its electric jurisdictional assets. Incorporating the 10.5% return on
the regulated electric utility with the Company's other existing productive
assets is expected to generate base earnings capacity of approximately $2.00 per
share. PNM will incur the risks and benefits of all off-system sales, cost
structure changes, plant availability and other earnings risks and
opportunities. PNM also plans to file a request for rate relief in its gas
utility business by the end of the year 2002. Any improvement in gas returns
through rate relief is not included in the base earnings capacity. However, the
ability to achieve or sustain this earnings level is largely dependent on the
timing of the shift to underground mining at SJGS, the ability to recognize the
expected cost savings related to the underground mining operation and a
favorable outcome from its planned gas rate filing.
To preserve the Company's strong financial position, management intends
to control expenses through on-going savings from the Realignment and other cost
control measures and plans to limit capital expenditures. Construction
expenditures in 2002, originally budgeted at $391 million, were reduced by $111
million to $280 million for the year. Planned construction expenditures through
2003 were reduced in total by over $400 million. The reduced capital
expenditures are related to a cut back of growth initiatives on the generation
side and will not affect PNM's ability to continue to provide reliable service
to its customers. On-going annual capital expenditures associated with the
electric and gas utility operations are expected to be in the range of $80 to
$100 million.
52
Although the current environment has led the Company to scale back its
expansion plans, the Company will continue to operate in the wholesale market.
Expansion of the Company's generating portfolio will depend upon acquiring
favorably priced assets at strategic locations and securing long-term
commitments for the purchase of power from those new plants.
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 discussed above.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2002, the Company had cash and short-term investments of
$139.5 million compared to $71.2 million in cash and short-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.
Cash provided from operating activities in the nine months ended
September 30, 2002 was $104.0 million compared to cash provided by operating
activities of $296.9 million for the nine months ended September 30, 2001. This
decrease was primarily the result of current wholesale market conditions. Also,
contributing to the decrease was the Company's $24.6 million contribution to its
pension and postretirement benefit plans. In addition, the Company did not make
its first quarter 2001 estimated federal income tax payment of $32.0 million
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 $136.6 million in 2002 compared to
$153.9 million in 2001. Cash used for investing activities includes construction
expenditures for new generating plants of $96.7 million in 2002 compared to
$68.0 million in 2001. These cash outflows were partially offset by the
redemption of short-term investments of $45.0 million. Expenditures in 2001
reflect the acquisition of certain transmission assets and other related
investing activities of $13.9 million.
53
Cash generated by financing activities was $36.5 million in 2002 compared
to $28.1 million of cash used in 2001. Financing activities in 2002 were
primarily short-term borrowings of $65.0 million 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
reflecting the events in the financial markets after September 11, 2001. As a
result, the Company had lowered its expected rate of return on its retiree
benefit plans assets. By year end 2001, markets had recovered significantly. As
a result, in 2002 the Company adjusted its return assumption to its historic
view of a 9% long-term rate of return. In addition, in January 2002, the Company
made an aggregate contribution of $23.5 million to fund pension and other
postretirement benefit plans. An additional aggregate contribution of $1.1
million was made in September 2002. The effect of the change in the expected
rate of return and the additional cash contributions was a decrease in pension
and other postretirement benefits expense for the nine months ended September
30, 2002 compared to the same period in the prior year.
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 and expanding its wholesale generation
capabilities; upgrading and expanding the electric and gas transmission and
distribution systems; and purchasing nuclear fuel. To preserve a strong
financial position, the Company plans to reduce its capital expenditures for
planned generation expansion. Projections for total capital requirements for
2002 are $298 million and projections for construction expenditures for 2002,
originally predicted to be $391 million, have been reduced by $111 million to
$280 million for the year. Planned construction expenditures through 2003 were
reduced in total by over $400 million. For 2002-2006 projections, total capital
requirements are $1.5 billion and construction expenditures are $1.4 billion,
including the combustion turbines discussed below. These estimates are under
continuing review and subject to on-going adjustment.
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 over the next five
years depending on market conditions. PNM has expended $208.8 million as of
September 30, 2002 of which $131.5 million was for equipment purchases. In
November 2001, PNM broke ground to build Afton Generating Station, a 135 MW
simple cycle gas turbine plant in southern New Mexico, which is expected to be
operational by the end of November 2002. In February 2002, PNM broke ground to
build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired
generating plant in southwestern New Mexico. On June 27, 2002, Lordsburg became
fully operational and commenced serving the wholesale power market. Construction
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. These plants were not built to serve New Mexico
retail customers and so have not been added to rate base. However, it is
possible that future growth in the New Mexico retail market will cause these
plants to be needed to serve New Mexico retail customers. In that case, the
plants will have to be certified by the PRC and would be added to rate base at
that time.
54
In the first nine months of 2002, the Company utilized cash generated
from operations, cash on hand, as well as its liquidity arrangements to cover
its construction commitments. The Company anticipates that internal cash
generation and current debt capacity will be sufficient to meet all its 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 current and future liquidity
arrangements.
Liquidity
As of November 1, 2002, PNM had $180 million of liquidity arrangements,
consisting of $150 million from an unsecured revolving credit facility ("Credit
Facility") and $30 million in local lines of credit. PNM has been in discussions
with its banks regarding renewal of the Credit Facility, which will expire in
March 2003. There were $100 million in borrowings against the Credit Facility as
of November 1, 2002. In addition, the Holding Company has $25 million in local
lines of credit.
The Company's ability, if required, to access the capital markets 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 stable by Moody's Investor Services,
Inc. ("Moody's") and Standard and Poor's Ratings Services ("S&P") and positive
by Fitch, Inc. ("Fitch"). 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 and to ultimately
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 ratings. 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 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.
55
Long-term Obligations and Commitments
The following table shows PNM's long-term debt and operating leases as of
September 30, 2002. As of September 30, 2002, PNM Resources, Inc. and
Subsidiaries have no long-term obligations except those acquired through
consolidation with PNM.
Payments Due
---------------------------------------------------------------
(In thousands)
Contractual Less than After
Obligations Total 1 year 2-3 years 4-5 years 5 years
------------ ------------ ----------- ----------- -------------
Long-Term Debt.................. $ 953,926 $ - $ - $268,420 $ 685,506
Operating Leases................ 508,883 32,811 67,452 70,969 337,651
------------ ------------ ----------- ----------- -------------
Total Contractual Cash
Obligations.................. $1,462,809 $32,811 $67,452 $339,389 $1,023,157
============ ============ =========== =========== =============
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 $9.9 million for the nine months
ended September 30, 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 $224 million as
of September 30, 2002.
PNM has entered various long-term power purchase agreements obligating it
to buy electricity for aggregate fixed payments of $27.7 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 $194.1 million in
fixed payments plus the cost of production and a return. These contracts expire
December 2003 through June 2010. PNM's trading portfolio as of September 30,
2002 included open contract positions to buy $38.3 million of electricity and to
sell $29.6 million of electricity. In addition, PNM had open forward positions
classified as normal sales of electricity under the derivative accounting rules
of $36.1 million and normal purchases of electricity of $70.6 million.
56
PNM contracts for the purchase of gas to serve its retail 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 PNM recovers 100% of its cost of gas.
SJGS Coal Supply
PNM has a coal supply contract for the needs of 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.
In August 2001, PNM signed an agreement with San Juan Coal Company
("SJCC"), the owner of the coal mine that supplies coal to SJGS, and Tucson
Electric Power Company to replace two surface mining operations with a single
underground mine located adjacent to the plant. Underground mining is expected
to provide a higher quality coal at a lower cost per ton.
The revised coal contract, entered into as a result of the move to an
underground mine, is expected to save PNM between $400 million and $500 million
in fuel costs over the next 16 years. Besides saving on fuel costs, the
cleaner-burning, less abrasive coal is expected to reduce PNM's share of the
plant's maintenance and operating expenses.
The underground mine began ramp-up operations on October 14, 2002. The
current plan includes a ramp-up to full station supply in approximately six
months. The last surface mine deliveries are expected by January 2003.
New Long-Term Power Contract
On October 21, 2002, PNM entered into an agreement with FPL Energy LLC
("FPL"), a subsidiary of FPL Group, Inc., to develop a 200 MW wind generation
facility in New Mexico.
FPL Energy will build, own and operate the New Mexico Wind Energy Center
("NMWE"), consisting of 136 wind-powered turbines on a site in eastern New
Mexico. PNM will buy all the power generated by the NMWE under a 25-year
contract. Construction of the wind energy site is expected to begin later this
year. Construction on a facility of this size typically takes six to nine months
to complete.
This project represents a significant step forward in reducing PNM's
reliance on fossil fuel generation while protecting PNM's competitive cost of
generation. For PNM, the NMWE will provide a long-term, competitively priced
power source both for New Mexicans and for the wholesale power market in the
Southwest.
PNM will ask the PRC to approve a voluntary tariff that will allow PNM
retail customers to buy wind-generated electricity for a small monthly premium.
Power from the facility not subscribed by PNM retail customers under the
voluntary program will be sold on the wholesale market, either within New Mexico
or outside the state.
PNM is buying this clean energy for several reasons: its environmental
benefits for New Mexico; interest within the state in renewable energy;
prospects for renewable energy on the wholesale energy market; and the strength
this particular wind contract will bring to PNM's competitive generation
portfolio and its overall fuel mix.
57
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 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 retail
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 Systems
Power Pool ("WSPP") contains a contingent requirement that could require PNM to
provide security if its debt were to fall below 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
September 30, 2002, PNM had $5.7 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.
Planned Financing Activities
PNM has $268.4 million of long-term debt that matures in August 2005. All
other long-term debt of PNM 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 and regulatory agreements would ultimately limit
the amount of additional debt PNM would issue.
58
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. The Company received regulatory approval to refund the tax-exempt
bonds on October 29, 2002. This approval is good for one year. In order to take
advantage of current low interest rates, PNM entered into five forward starting
interest rate swaps in the fourth quarter of 2001 and 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 4.95% 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. For the nine months ended September 30, 2002, PNM
recognized $0.4 million of hedge ineffectiveness in earnings. At September 30,
2002, the fair market value of these derivative financial instruments was
approximately $20.3 million unfavorable to the Company.
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 benchmark. The five forward starting
interest rate swaps have a termination date of May 15, 2003 for a combined
notional amount of $182.0 million. There were no fees on the transaction, as
they are imbedded in the rates, and the transaction 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.
On November 1, 2002, the Company filed for approval from the PRC to enter
into a transaction providing for the securitization of PNM's retail electric
service accounts receivable, wholesale electric service accounts receivables and
retail gas services accounts receivable ("Securitization") to reduce the amount
of debt outstanding under the Credit Facility and to raise cash for PNM's
ongoing working capital requirements and other capital requirements. The total
capacity, or maximum that could be borrowed, under the Securitization will not
exceed $100 million. In the proposed transaction, PNM would sell its accounts
receivables from time to time.
Dividends
The Holding Company's board of directors regularly reviews the dividend
policy. The declaration of common dividends is dependent upon a number of
factors including the ability of the Holding Company's subsidiaries to pay
dividends. Currently, PNM is the Holding 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 the
Holding Company. PNM cannot pay dividends that will 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 for that year without
prior PRC approval. Additionally, PNM has various financial covenants, which
limit the transfer of assets, through dividends or other means.
59
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
earnings, its financial circumstances and performance, the effect of regulatory
decisions and legislative activities, future growth plans, the related capital
requirements, standard business considerations and market economic conditions
generally.
Consistent with the PRC's holding company order, PNM paid dividends of
$127.0 million to the Holding Company on December 31, 2001. On March 4, 2002,
the PNM board of directors declared a dividend of $5.5 million, which was paid
on March 19, 2002. On June 10, 2002, the PNM board of directors declared a
dividend of $24.7 million, which was paid on June 28, 2002.
On February 19, 2002, the Holding Company's board of directors approved a
10 percent increase in the common stock dividend. The increase raised the
quarterly dividend to $0.22 per share, for an indicated annual dividend of $0.88
per share. The 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 September 30, 2002 and December 31, 2001 is shown below:
September 30, December 31,
2002 2001
------------- --------------
Common Equity.................... 51.4% 50.8%
Preferred Stock.................. 0.6 0.6
Long-term Debt................... 48.0 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 $224 million as of September 30, 2002 and
$225 million as of December 31, 2001.
OTHER ISSUES FACING THE COMPANY
RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY
State
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
60
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 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 would 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. Approximately $143 million of
costs associated with the power supply and energy services businesses under the
Restructuring Act, as amended 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.
On October 10, 2002, PNM announced that it had agreed with the PRC Staff,
the Attorney General, and other consumer groups on a stipulation that includes
agreement to support repeal of the Restructuring Act, as amended. The
stipulation, which includes agreement on a five year rate path, procedures for
the Company's participation in merchant plant activities and other regulatory
issues, must first be approved by the PRC before the parties' obligations to
support repeal becomes effective. The parties signing the stipulation have
proposed that the PRC approve the stipulation before the end of the year. The
PRC hearing examiner has not yet set a hearing date, but has scheduled a working
session and pre-hearing conference for November 19, 2002. The next legislative
session begins on January 21, 2003. The Company is unable to predict at this
time if restructuring will occur as provided in current law or, if so, what form
it will take. (See Merchant Plant Filing and Electric Rate Settlement below).
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.
An interim committee of the legislature is studying 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.
61
Federal
On April 25, 2002, by a vote of 88-11, the U.S. Senate (the "Senate")
passed amendments to HR4, 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 version voted on the House of Representative (the
"House"). As adopted by the Senate, H.R.4 contains provisions revising the
authority of the Federal Energy Regulation Commission (the "FERC") 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 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 the 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; and extends
protections against liability for nuclear accidents under the Price-Anderson
Act. The differences in the two versions of H.R.4 are the subject of conference
committee discussions. The Company is unable to predict when or if an agreement
will be reached between the House and the Senate and if so, what form energy
legislation will take, if energy legislation will be passed or if passed,
whether 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. On
October 10, 2002, the FERC issued a Declaratory Order, on Regional Transmission
Organization in response to WestConnect's October 15, 2001 Joint Petition for
Declaratory Order to Form WestConnect RTO, LLC Pursuant to Order 2000. The
Company continues to participate in this process.
To remedy what the FERC sees as undue discrimination in the provision of
interstate transmission services and to ensure just and reasonable rates for
sales of electric energy within and among regional power markets, the FERC has
approved a Notice of Proposed Rulemaking ("NOPR") for Standard Market Design.
The proposed rule would put all transmission customers, including bundled retail
customers, under new pro forma transmission rates for new transmission service.
All transmission will be operated under independent transmission providers
(including RTOs) and congestion management will be handled under locational
marginal pricing with tradable congestion revenue rights. The Company will be
making comments on the Standard Market Design NOPR along with the other
WestConnect companies and will continue to participate in the rulemaking
process. The Company is also following rulemakings of the FERC on Standards of
Conduct and Standardizing Generation Interconnection Agreements and Procedures
and has submitted comments or has commented in conjunction with WestConnect and
Edison Electric Institute.
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MERCHANT PLANT FILING AND ELECTRIC RATE SETTLEMENT
Senate Bill ("SB266"), enacted by the 2001 session of the New Mexico
legislature, allowed public utilities to "invest in, construct, acquire or
operate" generating plants not intended to provide retail electric service
("merchant plant"), 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 PRC can ensure the
utility will meet its duty to provide service when the utility invests in
merchant plant, how that plant will be financed and how transactions between
regulated services and merchant plants will be conducted. The PRC initiated
proceedings to address these issues.
In November 2001, PNM began settlement negotiations with the PRC utility
staff and intervenors in order to resolve its merchant plant filing and other
matters. Discussions included the future framework for restructuring the
electric industry in New Mexico under the Restructuring Act, a future retail
electric rate path and PNM's merchant plant filing.
The year-long negotiations ended on October 10, 2002, with the filing of
an agreement ("Agreement") with the PRC. If implemented, the Agreement will set
a rate path through 2007 and will resolve the issues surrounding industry
deregulation in New Mexico and the Company's merchant power strategy. The
Agreement was signed by PNM, the PRC Staff, the New Mexico Attorney General's
Office, the New Mexico Industrial Energy Consumers, the City of Albuquerque, and
the University of New Mexico. The United States Executive Agencies ("USEA")
initially filed a statement objecting to the Agreement, but on October 30, 2002
withdrew their objections and agreed to support the Agreement as if they had
signed it. The Agreement must be approved by the PRC and also provides for the
signatories to support passage of certain legislation in the New Mexico
Legislature. The parties to the Agreement have proposed that the PRC approve the
Agreement before the end of the year. The PRC hearing examiner has not yet set a
hearing date, but has scheduled a working session and pre-hearing conference for
November 19, 2002.
Under the Agreement, PNM would decrease retail electric rates 6.5% in two
phases over the next three years. The first phase would be a 4.0% decrease,
effective September 2003. The second phase would be a further 2.5% decrease from
current rate levels, effective in September 2005. Rates would then be frozen at
that level until the end of 2007. These new rates would place PNM's rates as the
sixth lowest in the Southwest and among the lowest half of utilities nationwide.
The Company expects to achieve necessary cost savings through additional cost
efficiencies. The risks and benefits of all off-system sales, other than the
dollar amounts of those already embedded in the stipulated rates, inure solely
to the Company's shareholders until December 2007. Since the new rate Agreement
does not provide for a fuel cost adjustment, the lower fuel costs sought to be
captured by shifting to underground mining for the coal supplies at SJGS will
flow through to the Company's earnings largely offsetting the reduction in
retail revenues.
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PNM would be able to seek a general rate adjustment during the rate
freeze period if complying with any new or changed environmental or tax law or
regulation, or a new broader application of existing environmental or tax laws
or regulations, would compromise its financial integrity. PNM also would be
permitted to capitalize all the reasonable costs of mandatory renewable energy
resources, including an after-tax cost of capital of 8.64% to be recorded
concurrently with the deferral of those costs.
PNM would be authorized to recover in the stipulated rates and future
retail rates, its New Mexico jurisdictional share of the decommissioning costs
associated with the San Juan, La Plata and Navajo Surface Coal Mines. PNM would
be allowed to recover up to $100 million of the costs, composed of approximately
$69 million in surface coal mine reclamation costs, and approximately $31
million of contract buyout costs. The costs would be amortized over 17 years
commencing September 1, 2003 and in equal amounts each year after 2004. PNM
would not seek to recover a return on the unamortized reclamation costs, but
could seek to recover a return on the unamortized contract buyout costs
remaining as of December 31, 2007 in future rate adjustment proceedings.
The stipulated rates would also provide for full recovery of nuclear
decommissioning costs accrued in accordance with the estimates in the applicable
decommissioning cost study during the rate freeze period for PNM's interests in
PVNGS Units 1 and 2. The portion of SJGS Unit 4 previously treated as an
excluded resource from PNM's New Mexico retail rates would be included as a
generation resource to serve PNM's New Mexico retail and wholesale firm
requirements customers' load. PNM's contracts to purchase power from Tri-State
Generation and Transmission Association, Inc., Delta Person Limited Partnership
and firm power from Southwestern Public Service Company would also be included
as generation resources to serve PNM's New Mexico retail and wholesale firm
requirements customers' load until each contract expires under the Agreement.
PRC approval or other authorization from the PRC would not be required
for PNM's merchant plant investment as long as PNM meets the following
conditions: (a) PNM does not invest more than $1.25 billion in merchant plant;
(b) PNM has an investment grade credit rating on a stand alone basis and on a
consolidated basis with PNM Resources; and (c) PNM spends at least $60 million
per year in gas and electric utility, non-merchant plant infrastructure needed
to maintain adequate and reliable service. No prior approval for merchant plant
participation would be required and expedited PRC approval would be available
for financing of merchant plant if certain specified financial conditions are
met. If PNM's credit rating on a stand alone or consolidated basis with the
Holding Company falls below investment grade, however, approvals are needed for
new merchant plant projects and for continuing to participate in merchant plant
projects of more than certain dollar value and under certain conditions.
PRC approval would not be required for PNM to transfer any part of its
interests in merchant plant or PVNGS Unit 3 from time to time to any other legal
entity, provided that the following conditions are met: (a) PNM's debt to
capital ratio will not exceed 65% after giving effect to the transfer and (b)
PNM's investment grade status on a stand-alone basis and on a consolidated basis
with the Holding Company will not be impaired by the transfer of merchant plant
or PVNGS Unit 3 at the time of transfer.
PNM further agreed in the Agreement that it will transfer all its
interests in merchant plant out of PNM by January 1, 2010. PNM will accelerate
the mandatory transfer to a date one year after PNM has completed expenditures
of $1.25 billion on merchant plant. PNM may seek a variance from the PRC at any
time prior to January 1, 2010 to extend or vacate the time or terms and
conditions requiring the transfer but not beyond January 1, 2015.
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Under the Agreement, if merchant plant or PVNGS Unit 3 is transferred to
a PNM affiliate, PNM's generation resources and the affiliate's generation
resources may be jointly dispatched at the merchant affiliate's sole discretion
until January 1, 2015. Joint dispatch of all utility, PVNGS Unit 3 or merchant
plant resources would be terminable at any time between 2008 and 2015 at PNM's
discretion, as long as the utility's dispatch capability is not impaired in any
way.
PNM agreed to forego its pursuit to recover the costs incurred in
preparing to transition to a competitive retail market in New Mexico. This will
result in a one-time write off of approximately $16.7 million, pre-tax, upon
approval by the PRC of the Agreement.
In the Agreement, PNM, PRC utility staff and intervenors agree to
actively support the repeal of most of the Restructuring Act of 1999. If the
repeal does not occur during the 2003 New Mexico Legislative Session, various
modifications to the conditions of the Agreement are triggered depending on how
long repeal is delayed.
In summary, the terms of this Agreement and the Company's continuing
efforts to control expenses offer significant benefits to both customers and
shareholders in the form of lower rates, a predictable rate path, and the
resolution of important issues affecting implementation of the Company's
strategic plan over the next several years.
The Company is currently unable to predict the impact these proceedings
may have on its plans to expand its generating capacity and its future financial
condition and results of 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 driven by a number of separate factors, including electric power
supply shortages in the Western United States during the first half of the year,
weather conditions, gas supply costs and transmission constraints. As a result
of these factors, 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.
These conditions resulted in the well-publicized "California energy
crisis" and in the bankruptcy filings of the California Power Exchange ("Cal
PX") and of Pacific Gas & Electric Company ("PG&E"), although the turmoil in the
western markets was not limited to California. However, over the last fifteen
months, conditions in the western wholesale power market have changed
substantially as the result of certain regulatory actions (see below), moderate
weather conditions, conservation measures, the construction of additional
generation, and a decline in natural gas prices, as well as the lingering
slowdown in the regional economy. These changes have placed and are expected to
continue to place downward pressure on wholesale electricity prices, with the
result that 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.
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In response to the turmoil in the Western energy market, the FERC
initially imposed a "soft" price cap of $150 per MWh for sales to the 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 modified by orders of the FERC 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.
Shortly thereafter, 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. This plan replaced the $150 per MWh soft cap previously
established and applied during periods of system emergency. Subsequently, the
FERC issued still another order that changed the previous orders and expanded
the price mitigation approach to the entire western region.
In July 2002, the FERC issued further orders to address wholesale power
prices in the western market. On July 11, the FERC established a price cap of
$91.87 per MWh for the period ending September 30, 2002. On July 17, the FERC
entered an order, which was to have taken effect October 1, 2002, raising the
price cap to $250 per MWh. However, the FERC extended the $91.87 per MWh price
cap through October 31, 2002. Once it becomes effective, the revised price cap
can be affected by other factors that could cause the cap to be below $250 per
MWh. According to the FERC, this price cap will spur new investment in
generation and will foster the eventual return of a robust competitive
marketplace. The July 17 order also established mechanisms to prevent power
suppliers from engaging in market manipulation activities.
As a result of the foregoing conditions in the Western market, the FERC
and other federal and state governmental authorities are conducting
investigations and other proceedings relevant to the Company and other sellers.
The more significant of these in relation to the Company are summarized below.
California Refund Proceeding
By order dated June 19, 2001, the FERC directed one of its administrative
law judges to convene a settlement conference to address potential refunds owed
by sellers into the California market. The settlement conference, in which PNM
participated, was ultimately unsuccessful, and the administrative law judge
recommended to the FERC that an evidentiary hearing be held to resolve the
dispute, suggesting that refunds were due; however, the estimated refunds were
significantly lower than those 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. Hearings on the refunds were held in September 2002
and the parties will be filing post-hearing positions. A recommended decision is
not anticipated until the end of 2002, with a FERC decision by approximately the
spring of 2003. The Company is unable to predict the ultimate outcome of this
FERC proceeding, or whether PNM will be directed to make any refunds as the
result of a FERC order.
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Pacific Northwest Refund Proceeding
In addition to the California refund proceedings, 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 sales into the Pacific Northwest, but the FERC has
not yet acted on this recommended decision. The Company is unable to predict the
ultimate outcome of this FERC proceeding, or whether PNM will be directed to
make any refunds as the result of an order by the FERC.
FERC Investigation of "Enron-Like" Trading Practices
The FERC has also initiated a market manipulation investigation,
partially in response to the bankruptcy filing of the Enron Corporation
("Enron") and to allegations that Enron may have engaged in manipulation of
portions of the Western wholesale power market. 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. PNM made its data submission on April 2,
2002. Subsequently, in May 2002, new Enron documents came to light that raised
additional concerns about Enron's trading practices. In light of these new
revelations, the FERC issued additional orders in the pending investigation
requiring sellers to respond to detailed questions by admitting or denying that
they had engaged in trading practices similar to those practiced by Enron and
certain other sellers, including so-called "wash" transactions. In its
responses, PNM denied that it had engaged in improper activities such as those
identified in Enron's memos and also denied engaging in "wash" transactions. The
Company admitted engaging in certain activities described in the memos that were
not improper. Where appropriate, PNM's responses addressed any arguable
similarities between any of its trading activities and those under investigation
by the FERC. The FERC staff has issued a preliminary report on its findings,
recommending that the FERC initiate formal investigative proceedings directed at
three companies and the FERC has done so. The Company was not one of these
companies named. The Company cannot predict the outcome of this investigation.
California Power Exchange and Pacific Gas and Electric Bankruptcies
In 2001, approximately $2 million in wholesale power sales by PNM 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 Cal 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. PG&E
subsequently also sought bankruptcy protection. PNM has filed its proofs of
claims in the Cal PX and PG&E bankruptcy proceedings. Total amounts due PNM 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. PNM was invoiced for $2.3 million as its
proportionate share under the Cal PX tariff. PNM, as well as a number of power
marketers and generators, filed complaints with the FERC to halt the Cal PX's
67
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.
California Attorney General Complaint
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"). PNM was
among the sellers identified in this complaint and the Company filed its answer
and motion to intervene. In its answer, PNM defended its pricing and challenged
the theory of liability underlying the California Attorney General's complaint.
On May 31, 2002, the FERC entered an order denying the rate relief requested in
the complaint, but directing sellers, including PNM, to comply with additional
reporting requirements with regard to certain wholesale power transactions. PNM
has made required filings under the May 31 order. The California Attorney
General filed a request for rehearing contesting the FERC decision. On September
23, 2002, the FERC issued its order denying the Attorney General's request for
rehearing. The California Attorney General has filed a petition for review in
the United States Court of Appeals for the Ninth Circuit. As addressed below,
the California Attorney General has also threatened litigation against PNM in
state court in California based on similar allegations.
California Attorney General Threatened Litigation
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 PNM of his intent to file a complaint
in California state court against PNM concerning its alleged failure to file
rates for wholesale electricity sold in California and for allegedly charging
unjust and unreasonable rates in the California markets. The letter invited PNM
to contact the California Attorney General's office before the complaint was
filed, and PNM has met twice with representatives of the California Attorney
General's office. Further discussions are contemplated. To date, a lawsuit has
not been filed by the Attorney General and the Company cannot predict the
outcome of this matter.
California Antitrust Litigation
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 Corporation ("Duke") and
related entities along with other named sellers into the California market and
numerous other "unidentified defendants." These lawsuits were consolidated for
hearing in state court in San Diego. On May 3, 2002, the Duke defendants in the
foregoing state court litigation served a cross-claim on PNM. 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. Several defendants have removed the case to federal court
and a motion is pending to remand the case back to state court. PNM has joined
with other cross-defendants in motions to dismiss the cross-claim. The Company
cannot predict the outcome of this matter.
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Block Forward Agreement Litigation
On February 1, 2002, PNM was served with a declaratory relief complaint
filed by the State of California in California state court. The state's
declaratory relief complaint seeks a determination that the state is not liable
for its commandeering of certain energy contracts known as "Block Forward
Agreements". The Block Forward Agreements were a form of futures contracts for
the purchase of electricity at below-market prices and served as security for
payment by PG&E and SCE for their electricity purchases through the Cal PX. When
PG&E and SCE defaulted on payment obligations incurred through the Cal PX, the
Cal PX moved to liquidate the Block Forward Agreements to satisfy in part the
obligations owed by PG&E and SCE. Before the Cal PX could liquidate the Block
Forward Agreements, California commandeered them for its own purposes. In March
2001, PNM and other similarly situated sellers of electricity through the Cal PX
filed claims for damages with the California state Victims Compensation and
Government Claims Board ("Victims Claims Board") on the theory that the state,
by commandeering the Block Forward Agreements, had deprived them of security to
which they were entitled under the terms of the Cal PX's tariff. The Victims
Claims Board filing was an administrative remedy that served as a mandatory
prerequisite to filing suit against the state for recovery of damages related to
the commandeering of the Block Forward Agreements. The Victims Claims Board
denied PNM `s claim on March 22, 2002. PNM filed a complaint against the State
of California in California state court on September 20, 2002 seeking damages
for the state's commandeering of the Block Forward Agreements and requesting
judicial coordination with the state's declaratory relief action filed in
February 2002 on the basis that the two actions raise essentially the same
issues. On September 27, 2002, the state court granted a six month stay of the
proceedings pending resolution of certain related issues before the FERC.
Credit Issues
As a result of the slowdown in the wholesale electric market and the
bankruptcy of a major trader in 2001, a significant number of companies that
trade in electricity have experienced liquidity problems, resulting in a
downgrade in their credit ratings. This has had the effect of reducing the
number of credit worthy companies in the market. Some companies have curtailed
their activity or exited the business altogether. The Company's credit risk is
monitored by its Risk Management Committee ("RMC"), 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 offsetting positions with its
customers. PNM trades with companies of various credit qualities. For those
companies who are not investment grade, the Company provides a minimal amount of
credit. For companies that are designated as key strategic business partners by
the RMC but are not investment grade, the Company attempts to obtain a parental
guarantee (if investment grade) or other acceptable collateral. Currently, 71%
of trading partners who are not investment grade have such credit enhancements
in place. In the current downturn, the Company may be exposed to credit risk if
any of its customers experience liquidity problems.
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, PNM began to sell
power to the Cal DWR. The Company has regularly monitored its credit risk with
regard to the Cal DWR sales and believes its exposure is prudent.
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In addition to sales directly to California, PNM 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 non-California power sales ultimately are resold in the
California market. To the extent these customers who sell power into California
are dependent on payment from California to make their payments to PNM, 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 allowance against revenue of
$12.0 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. As of December 31, 2001, $8.9 million was transferred to the
allowance for bad debt. The Company reduced its reserves by $0.6 million for the
nine months ended September 30, 2002 as a result of fewer trades from a lack of
liquidity, lower prices and lower volatility. Based on information available at
September 30, 2002, the Company believes the total allowance for anticipated
losses (exclusive of bad debt), currently established at $2.4 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.
TERMINATION OF WESTERN RESOURCES TRANSACTION
On November 9, 2000, the Company and Westar Energy, Inc. (formerly known
as Western Resources) ("Westar Energy") announced that both companies' boards of
directors approved an agreement under which the Company would acquire the Westar
Energy electric utility operations in a tax-free, stock-for-stock transaction.
The agreement required that Westar Energy split-off its non-utility businesses
to its shareholders prior to closing.
After adverse rulings by the Kansas Corporation Commission regarding the
proposed split-off pursuant to the agreement and regarding Westar Energy's
electric rates, the transaction was terminated. The Company sued Westar Energy
in New York state court for unspecified damages for breach of contract and for
declaratory judgment. Westar Energy countersued, claiming entitlement to
termination fees in the amount of $25 million, plus costs and fees, and other
unspecified damages.
On September 25, 2002, the Company and Westar Energy jointly announced
that they had settled the litigation with each party dismissing its claims
against the other party and each party bearing its own costs.
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, order PNM to
provide network transmission service to WAPA under PNM's Open Access
Transmission Tariff on behalf of the United States Department of Energy ("DOE")
as contracting agent for Kirtland Air Force Base ("KAFB").
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In 2001, the FERC issued a "proposed" order directing PNM to provide
transmission service, but left the terms of service to be negotiated by the
parties and subject to the final review and determination of the FERC. 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 reserved PNM'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 PNM to provide the service. WAPA requested rehearing of the April 12
order approving the settlement, and FERC has issued an order granting rehearing
of the April 12 order for the purpose of further consideration. PNM requested
rehearing of the April 29 final order. FERC denied WAPA's request for rehearing
of FERC's order, ruling in PNM's favor on the question of whether PNM is
required to provide credits to the customer's bills with respect to certain
facilities funded by the customer. In that same order, the FERC confirmed that
PNM's request for rehearing of a separate order had been denied because the FERC
did not act on PNM's request within thirty days. The Company filed an appeal of
the April 29 order in the United States Court of Appeals for the 10th Circuit.
The final briefs will be filed early next year. Oral argument still has not been
scheduled. 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 PNM makes to DOE,
the effect of the FERC's proposed order to provide transmission service depends
upon PNM's ability to sell the power to a different customer and the price that
PNM would obtain if it makes such a sale. Depending on market conditions, the
Company estimates that the impact of the order will be a loss of revenues of
approximately $3 to $6 million.
NEW SOURCE REVIEW RULES
In November 1999, the Department of Justice at the request of the
Environmental Protection Agency (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 New Source Review ("NSR") requirements and
in some cases the New Source Performance Standards ("NSPS") regulations, which
could result in the requirement to make costly environmental additions to older
power plants. Whether or not the EPA will prevail is unclear at this time. The
EPA has reached a settlement with one of the companies sued by the Justice
Department. Discovery continues in the pending litigation. No complaint has been
filed against PNM 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 PNM, advising PNM 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." PNM has responded to the NMED information request. In late
June 2002, PNM received another information request from the NMED for a list of
capital budget item projects budgeted or completed in 2001 or 2002. PNM has
responded to this NMED information request.
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The National Energy Policy released in May 2001 by the National Energy
Policy Development Group called for a review of the pending EPA enforcement
actions. As a result of that review, on June 14, 2002 the EPA announced its
intention to pursue steps to increase energy efficiency, encourage emissions
reductions and make improvements and reforms to the NSR program. The EPA
announced that, among other things, the NSR program had impeded or resulted in
the cancellation of projects that would maintain or improve reliability,
efficiency and safety of existing power plants. However, the EPA's June 2002
announcement contemplates further rulemakings on NSR-related issues and
expressly cautions that the announcement is not intended to affect pending NSR
enforcement actions. Therefore, the ultimate resolution of NSR-related issues
raised by the enforcement actions remains unclear and if the EPA were to prevail
in the position advanced in the pending litigation, 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.
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 PNM of GCT's intent to file a
so-called "citizen suit" under the Clean Air Act, alleging that PNM and
co-owners of the SJGS violated the Clean Air Act, and the implemention of
federal and state regulations, at SJGS. Pursuant to that notification, on May
16, 2002, the GCT filed suit in federal district court in New Mexico against PNM
(but not against the other SJGS co-owners). The suit alleges two violations of
the Clean Air Act and related regulations and permits. First, GCT argues that
the plant has violated, and is currently in violation of, the federal Prevention
of Significant Deterioration ("PSD") rules, as well as the corresponding
provisions of the New Mexico Administrative Code, at SJGS Units 3 and 4. Second,
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 lawsuit seeks penalties as well as
injunctive and declaratory relief. PNM filed its answer in federal court on June
6, 2002, denying the material allegations in the complaint. Discovery is
on-going. The plaintiffs have filed a motion for partial summary judgment on the
opacity issues, to which PNM's response was filed on November 6, 2002. A trial
date on liability issues has been scheduled on a trailing docket for June 2003.
Based on its investigation to date, the Company firmly believes that the
allegations are without merit and vigorously disputes the allegations. PNM has
always adhered and continues to adhere to high environmental standards as
evidenced by its ISO 14000 certification. The Company is, however, unable to
predict the ultimate outcome of the matter.
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 PNM line near the
location. The explosion destroyed a small building and injured two persons who
were working in the building. PNM's investigation indicates that the leak was an
isolated incident likely caused by a combination of corrosion and increased
pressure. PNM also is cooperating with an investigation of the incident by the
PRC's Pipeline Safety Bureau (the "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 PNM
by the injured persons along with several claims for property and business
interruption damages have been resolved. 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.
72
NAVAJO NATION TAX ISSUES
APS, the operating agent for Four Corners, 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. On August 15, 2002 PNM entered into a
settlement and closing agreement with the Navajo Nation which resolved all tax
issues relating to the generating facility but is continuing discussions to
resolve tax issues relating to transmission facilities. While the Company cannot
predict the outcome of the ongoing settlement discussions, the settlement will
not have a material impact on the results of operations and financial position
of the Company.
LANDOWNER ENVIRONMENTAL CLAIMS
In March 2002, a lawsuit was filed in New Mexico state court by a
landowner owning property in the vicinity of SJGS, against PNM and SJCC. The
lawsuit was served on the defendants on June 11, 2002. 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. PNM has denied the allegations of wrongdoing and is vigorously
defending this matter, but is unable to predict the outcome of this matter.
ARCHEOLOGICAL SITE DISTURBANCE
The Company hired a contractor, Great Southwestern Construction, Inc.
("Great Southwestern"), to conduct certain "climb and tighten" activities on a
number of electric transmission lines in New Mexico between July 2001 and
December 2001. Those lines traverse a mix of federal, state, tribal and private
properties in New Mexico. In late May 2002, the U.S. Forest Service ("USFS")
notified PNM that apparent disturbances to archeological sites had been
discovered in and around the rights-of-way for PNM's transmission lines in the
Carson National Forest in New Mexico. Great Southwestern performed "climb and
tighten" activities on those transmission lines. PNM has confirmed the existence
of the disturbances, as well as disturbances associated with certain arroyos
that may raise issues under section 404 of the Clean Water Act. PNM has given
the Corps of Engineers notice concerning the disturbances in arroyos. The Corps
of Engineers has acknowledged the Company's notice and asked PNM to cooperate in
addressing these disturbances. No formal or written demand by the USFS has been
made on the Company with respect to this matter, but the USFS has verbally
instructed PNM to undertake an assessment and possible related mitigation
measures with respect to the archeological sites in question. PNM has contracted
for an archeological assessment and a proposed remediation plan with respect to
the disturbances. PNM has provided Great Southwestern with notice and a demand
for indemnity. A subsequent preliminary investigation into other transmission
lines that were covered by the "climb and tighten" project indicated that there
are disturbances on lands governed by other federal agencies and Indian tribes.
PNM and Great Southwestern have provided notice of the potential disturbances to
these other agencies and tribes. No formal action has been initiated against PNM
and no notice of any contemplated action has been received. The Company has been
informed that the USFS has commenced a criminal investigation into Great
Southwestern's activities on this project. The Company is unable to predict the
outcome of this matter and cannot estimate with any certainty the potential
impact on the Company's operations.
73
DUGAN PRODUCTION CORPORATION LITIGATION
On July 30, 2002, Dugan Production Corp. filed a lawsuit in the County of
San Juan, New Mexico, against the SJCC. On September 2, 2002, the SJCC removed
the lawsuit to the United States District Court for the District of New Mexico.
The lawsuit seeks to enjoin the underground mining of coal from a portion of the
land that is to be used for the underground mine. The plaintiff also seeks
monetary damages.
The SJCC through leases with the federal government and the State of New
Mexico, owns coal interests with respect to the underground mine. The plaintiff,
through leases with the federal government, the State of New Mexico and certain
private parties, claims to own certain oil and gas interests in portions of the
land that is to be used for the underground mine. The plaintiff alleges that the
defendant's underground coal mining operations have or will interfere with
plaintiff's gas production and result in the dissipation of natural gas that it
otherwise would be entitled to recover. The plaintiff also alleges, and seeks a
declaration by the court, that the rights under its leases are senior and
superior to the rights of the SJCC.
The SJCC intends to vigorously dispute the litigation. On September 17,
2002, the SJCC filed a motion to dismiss the claims against it on several
grounds. Discovery for the lawsuit has not yet started. The Company cannot
predict the ultimate outcome of the litigation or whether the litigation will
adversely affect the amount of coal available, or the price thereof, for SJGS.
EXCESS EMISSIONS REPORTS
As required by law, whenever there are excess emissions from SJGS, due to
such causes as start-up, shutdown, upset, breakdown or certain other conditions,
PNM makes filings with the NMED. For almost two years, PNM has been in
discussions with NMED concerning excess emissions reports for the period between
January 1997 and July 2002. NMED is still in the process of investigating the
circumstances of these excess emissions and whether these emissions involve any
violation of applicable permits and regulations. PNM and NMED have entered into
several agreements tolling the running of the statute of limitations in order to
allow NMED to complete its review of these filings. The present tolling
agreement expires December 16, 2002. PNM has been advised by NMED counsel that
NMED is in the process of preparing a draft administrative compliance order
addressing certain claimed violations, but PNM has not seen this draft order and
has not had a chance to meet with NMED to address any violations that might be
claimed. The Company is unable to predict the outcome of this matter and cannot
estimate the potential impact on the Company's operations.
PRC Renewable Resources Rulemakings
By Notice of Proposed Rulemaking, dated February 26, 2002, the PRC
proposed the adoption of a new Rule 572 to encourage the development of
renewable energy in New Mexico. The notice provided for the filing of public
comments and scheduled a public hearing for April 23, 2002. After a workshop in
which at least 22 entities participated, PRC staff submitted a summary of
positions of the parties to the PRC, along with its recommendations. On October
1, 2002, the PRC issued an Amended Notice of Proposed Rulemaking proposing a
revised rule. Among other things, new proposed Rule 572 would establish a
renewable portfolio standard of 4% by 2004, increasing to 7% by 2007 and 10% by
2010. No more than 50% of a utility's renewable energy resources portfolio would
74
be allowed to be from any single type of renewable resource for purposes of
compliance with the portfolio standard. Other new developments on the revised
proposed rule include language regarding trading credits, net metering (of
renewable energy projects up to 100 kW), the deletion of interconnection
requirements (to be addressed in later rulemakings), and rural cooperatives
(included under the rule for reporting purposes and for purposes of having a
voluntary green pricing tariff, but excluded for purposes of the mandatory
renewable portfolio standard). The PRC is in the process of receiving comments
and a hearing is scheduled for November 24, 2002. Depending on the outcome of
this rulemaking, the makeup of PNM's generation resource portfolio could be
significantly different. The Company is unable to predict the outcome of this
rulemaking proceeding.
Santa Fe Generating Station ("Santa Fe Station")
PNM and the NMED conducted investigations of the gasoline and chlorinated
solvent groundwater contamination detected beneath PNM's former Santa Fe Station
site to determine the source of the contamination pursuant to a 1992 Settlement
Agreement ("Settlement Agreement") between PNM and the NMED. No source of
groundwater contamination was identified as originating from the site. However,
in June 1996, PNM received a letter from the NMED, indicating that the NMED
believed PNM is the source of gasoline contamination in a City of Santa Fe
municipal supply well and of groundwater underlying the Santa Fe Station site.
Further, the NMED letter stated that PNM was required to proceed with interim
remediation of the contamination pursuant to the New Mexico Water Quality
Control Commission regulations. In October 1996, PNM and the NMED signed an
amendment to the Settlement Agreement concerning the groundwater contamination
underlying the site. As part of the amendment, PNM agreed to spend approximately
$1.2 million for certain costs related to sampling, monitoring and the
development and implementation of a remediation plan.
The amended Settlement Agreement does not, however, provide PNM with a
full release from potential further liability for remediation of the groundwater
contamination. After PNM has expended the settlement amount, if the NMED can
establish through binding arbitration that the Santa Fe Station is the source of
the contamination, PNM could be required to perform further remediation that is
determined to be necessary. PNM continues to dispute any contention that the
Santa Fe Station is the source of the groundwater contamination and believes
that insufficient data exists to identify the sources of groundwater
contamination. PNM's aquifer characterization and groundwater quality reports
compiled from 1996 through 2000 strongly suggest groundwater contamination has
been drawn under the site by the pumping of the Santa Fe supply well. PNM and
the NMED, with the cooperation of the City of Santa Fe, jointly selected a 3 to
4 year remediation plan proposed by a remediation contractor. The City of Santa
Fe, PNM and the NMED entered into a memorandum of understanding concerning the
selected remediation plan and the operation of the municipal well adjacent to
the Santa Fe Station site in connection with carrying out the plan. On October
5, 1998, a new system began operation to treat groundwater produced by the Santa
Fe well to drinking water standards for municipal distribution and
bioremediation of groundwater contamination beneath the Santa Fe Station site.
Since the reactivation of the Santa Fe well, the groundwater treatment and
bioremediation systems have resulted in a marked reduction in contaminant
concentrations at the wellhead. However, contaminant concentrations at the
property boundary remain high.
75
By letter dated August 7, 2002, PNM provided written notice to the NMED
and the City of Santa Fe that PNM had satisfied its obligations with respect to
the gasoline contamination under the amended Settlement Agreement and stated its
intention to cease operation, effective October 5, 2002, of the wellhead and
bioremediation systems, and to discontinue monitoring and reporting with respect
to gasoline contamination at the site. The NMED responded with a written notice
of determination dated August 16, 2002 that PNM is the responsible party for
gasoline contamination at the site and requested that PNM refrain from cessation
of operation of the remediation systems, monitoring and reporting. In a meeting
held on September 5, 2002, the NMED indicated its intention to file a court
action seeking an order invalidating the binding arbitration provisions of the
amended Settlement Agreement and a declaratory judgment that PNM is the
responsible party for the gasoline contamination at the site. PNM, the NMED and
the City of Santa Fe have tentatively agreed to refrain from filing any actions
or invoking the dispute resolution provisions under the Settlement Agreement
pending further data review and negotiation with respect to the NMED's
determination. PNM has tentatively agreed to continue operation of the wellhead
treatment system at the site and to continue well monitoring and reporting to
the NMED through October 5, 2003. The Company cannot predict the outcome of
these negotiations with NMED.
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 results from the acquisition, construction
or development 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
financial condition and results of operations.
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 or financial
condition and results of operations.
76
Statement of Financial Accounting Standards No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"). In April 2002, the FASB issued SFAS 145. This
statement updates and clarifies existing accounting pronouncements for treatment
of gains and losses from extinguishment of debt and eliminates an inconsistency
between required accounting for sale-leaseback transactions and the required
accounting for certain lease modifications that have similar economic effects as
sale-leaseback transactions. In accordance with previous accounting standards,
gains and losses from extinguishment of debt were classified as extraordinary
gains and losses. The current statement permits gains and losses from
extinguishment of debt to be classified as ordinary and included in income from
operations, unless they are unusual in nature or occur infrequently and
therefore included as an extraordinary item.
Emerging Issues Task Force ("EITF") Issue 02-3 "Issues Related to
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities", EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" and Statement of Financial Accounting
Standards No. 133 ("SFAS 133") "Accounting for Derivative Instruments and
Hedging Activities". The Company evaluates its energy contracts to determine if
they meet the definition of a derivative and are therefore subject to the
accounting requirements of SFAS 133. If an energy contract is determined not to
be a derivative under SFAS 133, it is then evaluated under EITF 98-10 to
determine whether it meets the definition of a trading activity and should be
marked to market with gains and losses recognized in earnings and separately
disclosed in the financial statements. EITF 98-10 allowed a gross or net
presentation of these gains and losses in the statement of earnings. In June
2002, the EITF reached a consensus in EITF 02-3 that all energy trading
activities must be presented on a net margin basis rather than a gross basis in
the statement of earnings and further required that all prior periods be
reclassified to conform to the current period presentation. On October 25, 2002,
the EITF reached a consensus to rescind EITF 98-10 and will no longer allow
energy contracts that do not meet the definition of a derivative under SFAS 133
to be marked to market and recognized in current earnings. As a result, all
contracts which were marked to market under EITF 98-10 and must now be accounted
for under the accrual method will be written back to cost with any difference
included as a cumulative effect adjustment in the period of adoption. This
transition provision will be effective for the first quarter of 2003. The
disclosure provisions previously agreed to in EITF 02-3 have also been
rescinded. In addition, any contracts within Statement 133 that are trading or
held for trading and are settled physically should be reported on a net basis.
Any contracts within Statement 133 that are not considered trading and are
settled physically should be reported on a gross basis. The EITF has directed
the FASB staff to provide a definition of trading activities to be included in
the final written consensus of EITF 02-3. The decision to rescind EITF 98-10,
the uncertainty as to the ultimate definition of trading activities and the
October 2002 consensus as to the effective date for adoption of EITF 02-3 has
nullified the June 2002 consensus on net margin versus gross basis presentation.
Therefore, the Company has not reclassified its energy trading activities to a
net margin presentation as of September 30, 2002 and is currently assessing the
impact of the EITF's October consensus on the accounting for its energy contract
portfolio. The Company expects to adopt EITF 02-3 in its entirety in the first
quarter of 2003.
77
The SEC has indicated that financial statement reclassifications related
to periods previously audited by Arthur Andersen LLP ("Arthur Andersen") may
require the successor auditor to audit the prior periods and issue a new audit
report. Arthur Andersen audited the Company's financial statements for the
fiscal years 2001 and 2000. The successor auditor, Deloitte and Touche, has not
issued a new review report for the three and nine months ended September 30,
2001. However, Deloitte and Touche will perform an audit of the Companies'
financial statements for fiscal year 2001.
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 performance of generating units and transmission system, the transition to
the underground mine for the supply of coal to SJGS, the creditworthiness of the
Company's marketing and trading counterparties, 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, rulings issued by the PRC pursuant to the Electric Utility
Industry Restructuring Act of 1999, as amended, on the recently filed agreement
regarding merchant plant and a five year rate path, 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.
78
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. 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 Holding Company Board of Directors. The Board's Finance
Committee 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 unit's 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.
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.
79
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. PNM 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 PNM's aggregate net open position is covered by its own excess
generation capabilities. PNM is exposed to market risk if its generation
capabilities were disrupted or if its retail load requirements were greater than
anticipated. If PNM 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 PNM'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 electric generation in excess of its
retail needs or the purchase of power for retail needs as non-trading. Purchases
for resale and subsequent resales are accounted for as energy trading contracts.
With respect to PNM's trading portfolio, the VAR was $34.1 thousand at September
30, 2002. The Company calculates a portfolio VAR, which in addition to its
trading portfolio includes all non-trading designated contracts, its generation
assets excluded from retail rates and any capacity in excess of retail needs.
This excess is determined using average peak forecasts for the respective block
of power in the forward market. The Company's portfolio VAR was $3.9 million at
September 30, 2002.
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The following table shows the high, average and low market risk as
measured by VAR on the Company's trading portfolio:
Nine Months Ended
September 30, 2002
--------------------------------------
High Average Low
---------- ----------- ---------
(In thousands)
$1,298 $584 $34
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 PNM'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 PNM's wholesale power marketing portfolio
during the year.
In addition, PNM is exposed to credit losses in the event of
non-performance or non-payment by counterparties. The Company uses a credit
management process to assess and monitor the financial conditions of
counterparties. Credit exposure is also regularly monitored by the RMC. The
Company provides for losses due to market and credit risk. PNM's credit risk
with its largest counterparty as of September 30, 2002 was $3.9 million.
(Intentionally left blank)
81
The following table provides information related to PNM's credit
exposure, net of collateral as of September 30, 2002. It further delineates that
exposure by the credit worthiness (credit rating) of the counterparties and
provides guidance as to the concentration of credit risk to individual
counterparties PNM may have.
Schedule of Credit Risk Exposure on Mark-To-Market Energy Contracts Net Assets
September 30, 2002
Exposure Net
Before Number of Exposure of
Credit Credit Counter- Counter-
Collateral Collateral parties parties
Rating (a) 1(b) (c) Net Exposure >10% >10%
- ------------------------- ------------ ------------- -------------- --------- ------------
(In thousands)
Investment grade......... $14,744 $ - $14,744 1 $3,878
Non-investment grade - - - -
Split rating............. 4,052 - 4,052 1 3,630
Internal ratings
Investment grade...... 1,101 - 1,101 -
Non-investment
grade............... 13,074 3,543 9,531 -
------------ ------------- -------------- ------------
Total............ $32,971 $3,543 $29,428 $7,508
============ ============= ============== ============
Credit reserves $2,433
==============
(a) Rating - Included in "Investment Grade" are counterparties with a
minimum Standard & Poor's rating of BBB- or Moody's rating of Baa3. If
the counterparty has provided a guarantee by a higher rated entity (e.g.,
its parent), determination is based on the rating of its guarantor. The
"Internal Rated - Investment Grade" includes those counterparties that
are internally rated as investment grade in accordance with the
guidelines established in the Company's credit policy.
(b) The Exposure Before Credit Collateral is the net credit exposure to PNM
from its wholesale trading activities. This includes trading contracts,
forward physical contracts, and firm off-system contracts. The exposure
captures the net amounts due to PNM from receivables/payables for
realized transactions, delivered and unbilled revenues, and
mark-to-market gains/losses (pursuant to contract terms). Exposures are
offset according to legally enforceable netting arrangements. Amounts are
presented before those reserves that are determined on a portfolio basis.
(See Western United States Wholesale Power Market in Item 2. Management's
Discussion and Analysis of Financial Condition and Results of Operations
for discussion of the reserves.)
(c) The Credit Collateral reflects the face amount of cash deposits, letters
of credit, and performance bonds received from counterparties.
PNM hedges certain portions of natural gas supply contracts in order to
protect its retail 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 purchased gas
adjustment clause. As a result, earnings are not affected by gains and losses
generated by these instruments.
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Interest Rate Risk
As of September 30, 2002, the Company has an investment portfolio of
fixed-rate government obligations and corporate securities, which were 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 September 30, 2002, the fair
value of these instruments would decline by 0.7% or $0.8 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
and obligors and limits credit exposure to high investment grade quality
investments.
PNM 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 4.15% or $40.0
million if interest rates were to decline by 50 basis points from their levels
at September 30, 2002. As of September 30, 2002, the fair value of PNM's
long-term debt was $963.6 million as compared to a book-value of $953.9 million.
In general, an increase in fair value would impact earnings and cash flows if
PNM were to re-acquire all or a portion of its debt instruments in the open
market prior to their maturity. Certain issuances of the debt have call dates in
December 2002 and August 2003. To hedge against the risk of rising interest
rates and their impact on the economics of calling the debt, PNM has entered
into forward starting interest rate swaps in 2001 and 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 4.95% plus an adjustment
for PNM's and industry's credit rating. At September 30, 2002, the fair market
value of these derivative financial instruments was approximately $20.3 million
unfavorable to the Company.
PNM contributed $6.1 million in 2001 to a trust established to fund
decommissioning costs for PVNGS. In January 2002, PNM contributed $23.5 million
for plan year 2001 to the trust for the Company's pension plan, and other post
retirement benefits. Additional contributions of $1.1 million were made in
September 2002 for the 2002 plan year. The securities held by the trusts had an
estimated fair value of $423 million as of September 30, 2002, of which
approximately 32% 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 September 30, 2002, the
decrease in the fair value of the securities would be 3.1% or $4.2 million. PNM
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.
83
Equity Market Risk
As discussed above under Interest Rate Risk, PNM contributes to trusts
established to fund its share of the decommissioning costs of PVNGS and pension
and other postretirement benefits. The trust holds certain equity securities as
of September 30, 2002. These equity securities also expose the Company to losses
in fair value. Approximately 60% of the securities held by the various trusts
were equity securities as of September 30, 2002. Similar to the debt securities
held for funding decommissioning and certain pension and other postretirement
costs, PNM 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 & Poor's 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 has VAR and stop loss limits
established. Trades are typically closed-out before the end of a reporting
period and within the same day of execution. The VAR at September 30, 2002 was
$44 thousand, utilizing a one-day, two-tailed, 99% confidence interval.
Recently, the RMC recommended and the Finance Committee approved the use of
derivatives based on the Nasdaq composite index.
Financial Instruments
Under the derivative accounting rules and the related accounting rules
for energy trading activities, the Company accounts for its various financial
derivative instruments for the purchase and sale of energy differently based on
management's intent when entering into the contract. Energy trading contracts
are recorded at fair market value at each period end. The changes in fair market
value are recognized in earnings. Non-trading contracts must be accounted for as
derivatives and recorded in the balance sheet as either an asset or liability
measured at their fair value. Changes in the derivatives' fair value are
recognized currently in earnings unless specific hedge accounting or normal
purchase and sale criteria are met. Should an energy transaction qualify as a
hedge, fair market value changes from period to period are recognized on the
balance sheet with a corresponding charge to other comprehensive income. Gains
or losses are recognized when the hedged transaction occurs. Normal purchases
and sales are not marked-to-market but rather recorded in results of operations
when the underlying transaction occurs.
84
The following table shows how the net fair value of energy trading
contracts was derived from the amounts included in the balance sheet:
September 30, December 31,
2002 2001
------------ -------------
(In thousands)
Energy Trading and Derivative Contracts:
Current asset....................................... $ 4,165 $ 9,461
Long-term asset..................................... 393 1,470
------------ -------------
Total mark-to-market assets...................... 4,558 10,930
------------ -------------
Current liability................................... (11,975) (36,256)
Long-term liability................................. (915) (5,115)
------------ -------------
Total mark-to-market liabilities................. (12,890) (41,370)
------------ -------------
Net fair value of energy trading contracts and
related derivatives................................. $ (8,333) $ (30,440)
============ =============
The trading portfolio positions at September 30, 2002 and December 31,
2001 represent net liabilities after netting all open purchase and sale
contracts. Because the contractual amounts required to settle the net liability
were greater than the current market values of the contracts, the Company
recognized mark-to-market losses for the differences in 2002 and 2001.
The market prices used to value PNM's energy trading contracts are based
on closing exchange prices and over-the-counter quotations. As of September 30,
2002 and December 31, 2001, PNM did not have any outstanding contracts that were
valued using methods other than quoted prices. The Company did not change its
methods for valuing its trading contracts in 2002 as compared to 2001.
The following table provides detail of changes in the Company's
mark-to-market net asset or liability balance sheet position from one period to
the next.
Nine Months Ended
September 30,
2002 2001
------------- --------------
(In thousands)
Sources of Fair Value Gain/(Loss)
Fair value at beginning of year.............. $(30,440) $ (4,643)
Amount realized on contracts delivered
during period............................. 19,903 2,736
Changes in fair value........................ 2,204 (29,520)
------------- --------------
Net fair value at end of period.............. $ (8,333) $(31,427)
============= ==============
Net change recorded as mark-to-market........ $22,107 $(26,784)
============= ==============
85
This table provides the maturity of the net assets/liabilities of the
Company, giving an indication of when these mark-to-market amounts will settle
and generate cash.
Fair Value of Contracts at September 30, 2002
Maturities
-----------------------------------------------
Less than
Sources of Fair Value 1 year 1-3 Years Total
- ------------------------- ------------- ------------- --------------
(In thousands)
Trading.................. $(7,811) $ (522) $ (8,333)
Note: All values determined using broker quotes.
As of September 30, 2002, a decrease in market pricing of PNM's trading
contracts by 10% would have resulted in a decrease in net earnings of less than
1%. Conversely, an increase in market pricing of the trading contracts by 10%
would have resulted in an increase in net earnings of less than 1%.
At September 30, 2002, the market value of PNM's normal sales and
purchases of electricity was a $20.7 million asset using the valuation methods
described above. If these transactions were classified as trading or did not
meet the definition of normal under the accounting rules for derivatives, the
Company would have recognized unrealized gains of $22.4 million as an adjustment
to Generation and Trading operating revenues based on the change in fair value
of these contracts from January 1, 2002 to September 30, 2002.
In addition to the fair market valuation described above, the Company
provides for losses due to market and credit risk in the electric wholesale
marketplace based on its assessment of counterparty default risk. This
assessment is based on a methodology that considers the credit ratings of
counterparties, the price volatility in the marketplace, the fair market value
of all contracts outstanding and management's evaluation of market trends that
are expected to impact market risk. The resulting amount is recorded as an
adjustment to revenue. As a result of fewer trades from a lack of liquidity,
lower prices and lower volatility, the Company recognized an increase in
revenues of $0.6 million for the nine months ended September 30, 2002.
ITEM 4. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures.
The Company's principal executive officer and principal financial officer
have concluded that the Company's disclosure controls and procedures, based on
their evaluation on October 9, 2002 of these disclosure controls and procedures,
are effective to ensure that material information relating to the Company,
including its consolidated subsidiaries, was made known to them by others within
those entities, particularly during the period in which the periodic reports are
being prepared.
(b) Changes in internal controls.
None.
86
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 2001 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.
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 PNM 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.
87
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,
the EPA and other parties have requested that the Court stay any further
briefing while they negotiate a settlement.
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, PNM was informed that the DOE had entered into an agency
agreement with WAPA on behalf of KAFB, one of PNM'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, PNM
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 PNM's transmission system. PNM 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. PNM 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 PNM to provide network transmission service to WAPA on behalf of
DOE and several other entities located on KAFB under PNM'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, the FERC granted WAPA's
request for rehearing. The FERC determined that WAPA qualified for an exemption
to the prohibition against an order requiring service to retail customers and
that the FERC therefore could require PNM to provide the requested service. The
FERC directed PNM 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 the 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 the FERC reserved PNM'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 PNM to provide service. WAPA requested rehearing of the April 12 order
88
approving the settlement, and the FERC issued an order granting rehearing for
further consideration. PNM requested rehearing of the April 29 final order
directing PNM to provide service. The FERC denied WAPA's request for rehearing
of the FERC's order, ruling in PNM's favor on the question of whether PNM is
required to provide credits to the customer's bills with respect to certain
facilities funded by the customer. In that same order, the FERC confirmed that
PNM's request for rehearing of a separate order had been denied because the FERC
did not act on PNM's request within thirty days.
The Company filed a petition for review of the FERC Final Order in the
United States Court of Appeals for the Tenth Circuit. The Company, USEA and WAPA
have entered a binding memorandum of understanding potentially resolving the
dispute. The memorandum provides that, if the agreement currently before the PRC
resolving the Company's electric rate path and merchant plant issues described
earlier in (wherever it is described) is approved by the PRC and becomes
effective, the Company will dismiss its appeal at the Tenth Circuit and WAPA
will purchase from the Company approximately 60 MW of electric power that will
be wheeled under the FERC Final Order to serve KAFB. The power sales agreement
between WAPA and the Company will last at least 6 years. The parties to the
memorandum have agreed that the appeal proceedings in the Tenth Circuit will be
suspended until the outcome of the PRC proceeding is known and service commences
under the power sales agreement. If the outcome is not known by March 20, 2003,
the memorandum provisions concerning dismissal of the appeal and the power sales
agreement can be voided. Should the memorandum provisions become void and should
DOE on behalf of KAFB choose to use WAPA for purchase and transmission 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. Depending on market conditions, the
Company estimates that the impact of the order will be a loss of revenues of
approximately $3 to $6 million.
In a separate but related proceeding, PNM 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 PNM provides retail service to
KAFB. PNM 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.
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, agreeing that the City would offer employment to the water utility
employees when this agreement expired. This 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.
89
In July 2001, the Maintenance and Operations Agreement ended, and most of
the water operations employees accepted employment with the City. However, on
March 27, 2001, the IBEW filed a 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 arbitrated the dispute in May 2002 and on
July 24, 2002, the arbitrator issued a written decision in favor of the Company
denying the grievance.
WESTAR ENERGY
On November 9, 2000, the Company and Westar Energy announced that both
companies' boards of directors approved an agreement under which the Company
would acquire the Westar Energy electric utility operations in a tax-free,
stock-for-stock transaction. The agreement required that Westar Energy split-off
its non-utility businesses to its shareholders prior to closing.
After adverse rulings by the Kansas Corporation Commission regarding the
proposed split-off pursuant to the agreement and regarding Westar Energy's
electric rates, the transaction was terminated. The Company sued Westar Energy
in New York state court for unspecified damages for breach of contract and for
declaratory judgment. Westar Energy countersued, claiming entitlement to
termination fees in the amount of $25 million, plus costs and fees, and other
unspecified damages.
On September 25, 2002, the Company and Westar Energy jointly announced
that they had settled the litigation between them, with each party dismissing
its claims against the other party and each party bearing its own costs.
California Attorney General Complaint
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 Cal DWR. PNM was among the sellers identified in this
complaint and filed its answer and motion to intervene. In its answer, PNM
defended its pricing and challenged the theory of liability underlying the
California Attorney General's complaint. On May 31, 2002, the FERC entered an
order denying the rate relief requested in the complaint, but directing sellers,
including PNM, to comply with additional reporting requirements with regard to
certain wholesale power transactions. PNM has made required filings under the
May 31 order. The California Attorney General filed a request for rehearing
contesting the FERC's decision. On September 23, 2002, the FERC issued its order
denying the California Attorney General's request for rehearing.
California Antitrust Litigation
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 and related entities along with other
named sellers into the California market and numerous other "unidentified
defendants." These lawsuits were consolidated for hearing in state court in San
Diego. On May 3, 2002, the Duke defendants in the foregoing state court
90
litigation served a cross-claim on PNM and 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. Several defendants have
removed the case to federal court and a motion is pending to remand the case to
state court. PNM has joined with other cross-defendants in motions to dismiss
the cross-claim. The Company cannot predict the outcome of this matter.
Citizen Suit Under the Clean Air Act
By letter dated January 9, 2002, counsel for the GCT notified the Company
of GCT's intent to file a so-called "citizen suit" under the Clean Air Act,
alleging that PNM and co-owners of the SJGS violated the Clean Air Act, and the
implemention of federal and state regulations, at SJGS. Pursuant to that
notification, on May 16, 2002, the GCT filed suit in federal district court in
New Mexico against PNM (but not against the other SJGS co-owners). The suit
alleges two violations of the Clean Air Act and related regulations and permits.
First, 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 SJGS Units 3 and 4. Second, 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
lawsuit seeks penalties as well as injunctive and declaratory relief. PNM filed
its answer in federal court on June 6, 2002, denying the material allegations in
the complaint. Discovery is on-going. The plaintiffs have filed a motion for
partial summary judgment on the opacity issues, to which the Company's response
was filed on November 6, 2002. A trial date on liability issues has been
scheduled on a trailing docket for June 2003. Based on its investigation to
date, PNM believes that the allegations are without merit and vigorously
disputes the allegations. PNM has always adhered and continues to adhere to high
environmental standards as evidenced by its ISO 14000 certification. The Company
is, however, unable to predict the ultimate outcome of the matter.
LANDOWNER ENVIRONMENTAL CLAIMS
In March 2002, a lawsuit was filed in the eleventh judicial district of
the state of New Mexico by a landowner, owning property in the vicinity of SJGS,
against PNM and the SJCC. The lawsuit was served on the defendants on June 11,
2002. 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. PNM has denied the allegations of
wrongdoing and is vigorously defending this matter, but is unable to predict the
outcome of this matter.
91
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
10.74.5 Fifth Amendment to the Third Restated and Amended PNM
Resources, Inc. Performance Stock Plan (formerly, the
Public Service Company of New Mexico Performance Stock
Plan)
15.1 Letter Re: Unaudited Interim Financial Information for
PNM Resources, Inc. and Subsidiaries.
15.2 Letter Re: Unaudited Interim Financial Information for
Public Service Company of New Mexico.
99.1 Chief Executive Officer Certification Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
99.2 Chief Financial Officer Certification Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
b. Reports on Form 8-K:
Report dated and filed August 14, 2002 reporting the Company, Pursuant to the
order issued by the Securities Exchange Commission ("SEC") on June 27, 2002,
Jeffry E. Sterba, Chairman, Chief Executive Officer and President of PNM
Resources, Inc. (the Company) and Max H. Maerki, Senior Vice President and Chief
Financial Officer of the Company, filed their sworn statements regarding facts
and circumstances relating to exchange act filings with the SEC on August 14,
2002.
Report dated and filed August 19, 2002 reporting the Company's Comparative
Operating Statistics for the month of July 2002 and 2001 and the year ended July
2002 and 2001.
Report dated and filed August 23, 2002 reporting the Company Realigns to Capture
Efficiencies and Respond to Declining Wholesale Market, Work Force Reduced and
Chief Operating Officer Named.
Report dated and filed September 13, 2002 reporting the Company's Comparative
Operating Statistics for the month of August 2002 and 2001 and the year ended
August 2002 and 2001.
Report dated and filed September 18, 2002 reporting the Company's Response to
the Federal Energy Regulatory Commission's ("FERC") request for information
pertaining to the Company's FERC Form 1 for the years 2000 and 2001.
Report dated and filed September 26, 2002 reporting the Company and Westar
Energy Drop Lawsuit.
Report dated and filed September 27, 2002 reporting the Company Declares
Preferred Dividends.
Report dated and filed October 4, 2002 reporting the Company Declares Common
Stock Dividend.
Report dated and filed October 11, 2002 reporting the Company Announces to set
five-year rate path and projected cost savings will offset lower rates.
92
Report dated and filed October 15, 2002 reporting the Company's Comparative
Operating Statistics for the month of September 2002 and 2001 and the year ended
September 2002 and 2001.
Report dated and filed October 22, 2002 reporting the Company has entered into
an agreement with FPL Energy LLC, a subsidiary of FPL Group, Inc. to develop a
200 megawatt wind generation facility in New Mexico.
Report dated and filed October 30, 2002 reporting the Company's quarter ended
September 30, 2002 Earnings Announcement, Consolidated Statement of Earnings,
Consolidated Balance Sheets, Consolidated Statement of Cash Flow and Comparative
Operating Statistics.
93
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
---------------------------------------------
(Registrant)
Date: November 12, 2002 /s/ John R. Loyack
---------------------------------------------
John R. Loyack
Vice President and Chief Accounting Officer
(Officer duly authorized to sign this report)
94
CERTIFICATIONS:
I, Jeffry E. Sterba, certify that:
1. I have reviewed this quarterly report on Form 10-Q of PNM Resources,
Inc. and Public Service Company of New Mexico;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
95
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes
in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: November 12, 2002
/s/ Jeffry E. Sterba
- ----------------------------------
Jeffry E. Sterba,
Chairman, President and Chief Executive Officer
96
I, Max H. Maerki, certify that:
1. I have reviewed this quarterly report on Form 10-Q of PNM Resources,
Inc. and Public Service Company of New Mexico;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
97
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes
in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: November 12, 2002
/s/ Max H. Maerki
- ----------------------------------
Max H. Maerki,
Senior Vice President and Chief Financial Officer
98