UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITES EXCHANGE ACT OF 1934
For the period ended June 30, 2002
- OR -
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _________________
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
----------- ---------------------------- ------------------
333-32170 PNM Resources, Inc. 85-0468296
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
1-6986 Public Service Company of New Mexico 85-0019030
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
Securities Registered Pursuant To Section 12(b) Of The Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
---------- ------------------- ---------------------
PNM Resources, Inc. Common Stock, No Par Value New York Stock Exchange
|
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 August 1, 2002 ---------- ----- ----------------------------- PNM Resources, Common Stock, No Par Value 39,117,799 Inc. |
PNM RESOURCES, INC. AND SUBSIDIARIES
INDEX
Page No.
PART I. FINANCIAL INFORMATION:
Reports of Independent Public Accountants............................ 3
ITEM 1. FINANCIAL STATEMENTS
PNM Resources, Inc.
Consolidated Statements of Earnings
Three and Six Months Ended June 30, 2002 and 2001......... 7
Consolidated Balance Sheets
June 30, 2002 and December 31, 2001....................... 8
Consolidated Statements of Cash Flows
Six Months Ended June 30, 2002 and 2001................... 10
Consolidated Statements of Comprehensive Income
Three and Six Months Ended June 30, 2002 and 2001......... 11
Public Service Company of New Mexico
Consolidated Statements of Earnings
Three and Six Months Ended June 30, 2002 and 2001......... 12
Consolidated Balance Sheets
June 30, 2002 and December 31, 2001....................... 13
Consolidated Statements of Cash Flows
Six Months Ended June 30, 2002 and 2001................... 15
Consolidated Statements of Comprehensive Income
Three and Six Months Ended June 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............ 31
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.............................................. 70
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS........................................... 74
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 80
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................ 81
Signature ......................................................... 82
|
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of PNM Resources, Inc. Albuquerque, New Mexico
We have reviewed the accompanying consolidated balance sheet of PNM Resources, Inc. and subsidiaries (the Company) as of June 30, 2002, and the related consolidated statements of earnings, cash flows and comprehensive income for the three-month and six-month periods then ended. These financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and 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 June 30, 2002, and for the three- and six-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 six-month periods ended June 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
August 2, 2002
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 consolidated balance sheet of Public Service Company of New Mexico (the Company) as of June 30, 2002, and the related consolidated statements of earnings, cash flows and comprehensive income for the three-month and six-month periods then ended. These financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and 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 June 30, 2002, and for the three- and six-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 six-month periods ended June 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
August 2, 2002
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 June 30, 2001, and the related condensed consolidated statements of earnings for the three-month and six-month periods ended June 30, 2001 and 2000, and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 2001 and 2000. These financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet and statement of capitalization of Public Service Company of New Mexico and subsidiaries as of December 31, 2000, and the related consolidated statements of earnings, and cash flows for the year then ended (not presented separately herein), and in our report dated January 26, 2001, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2000 is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
August 13, 2001
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
ITEM 1. FINANCIAL STATEMENTS
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands, except per share amounts)
Operating Revenues:
Electric................................... $220,516 $577,730 $424,479 $1,122,324
Gas........................................ 43,968 87,084 153,169 279,020
Unregulated businesses..................... 85 1,277 917 1,277
------------ ------------ ------------ ------------
Total operating revenues................. 264,569 666,091 578,565 1,402,621
------------ ------------ ------------ ------------
Operating Expenses:
Cost of energy sold........................ 122,692 433,841 277,800 930,939
Administrative and general................. 36,389 38,768 68,453 78,256
Energy production costs.................... 34,202 37,878 69,173 72,903
Depreciation and amortization.............. 25,217 23,929 49,996 48,148
Transmission and distribution costs........ 15,451 15,080 31,988 30,357
Taxes, other than income taxes............. 9,028 7,839 17,512 15,056
Income taxes............................... 2,141 28,209 11,507 69,115
------------ ------------ ------------ ------------
Total operating expenses................. 245,120 585,544 526,429 1,244,774
------------ ------------ ------------ ------------
Operating income......................... 19,449 80,547 52,136 157,847
------------ ------------ ------------ ------------
Other Income and Deductions:
Other income............................... 10,812 13,852 23,006 27,229
Other deductions........................... (983) (35,918) (947) (44,735)
Income tax (expense) benefit............... (3,432) 7,478 (8,274) 5,552
----------- ------------ ------------ ------------
Net other income and deductions.......... 6,397 (14,588) 13,785 (11,954)
------------ ------------ ------------ ------------
Income before interest charges........... 25,846 65,959 65,921 145,893
------------ ------------ ------------ ------------
Interest Charges............................. 14,689 16,362 29,815 32,744
------------ ------------ ------------ ------------
Net Earnings................................. 11,157 49,597 36,106 113,149
Preferred Stock Dividend Requirements........ 147 147 293 293
------------ ------------ ------------ ------------
Net Earnings Applicable to Common Stock...... $ 11,010 $ 49,450 $ 35,813 $ 112,856
============ ============ ============ ============
Net Earnings per Common Share:
Basic...................................... $ 0.28 $ 1.26 $ 0.92 $ 2.89
============ ============ ============ ============
Diluted.................................... $ 0.28 $ 1.24 $ 0.90 $ 2.84
============ ============ ============ ============
Dividends Paid per Share of Common Stock..... $ 0.22 $ 0.20 $ 0.42 $ 0.40
============ ============ ============ ============
|
The accompanying notes are an integral part of these financial statements.
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001
-------------- --------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service..................................... $2,179,468 $2,118,417
Gas plant in service.......................................... 595,397 575,350
Common plant in service and plant held for future use......... 49,527 45,223
-------------- --------------
2,824,392 2,738,990
Less accumulated depreciation and amortization................ 1,272,484 1,234,629
-------------- --------------
1,551,908 1,504,361
Construction work in progress................................. 232,733 249,656
Nuclear fuel, net of accumulated amortization of
$16,455 and $16,954....................................... 26,586 26,940
-------------- --------------
Net utility plant........................................... 1,811,227 1,780,957
-------------- --------------
Other Property and Investments:
Other investments............................................. 430,370 552,453
Non-utility property, net of accumulated depreciation of
$1,665 and $1,580......................................... 1,613 1,784
-------------- --------------
Total other property and investments........................ 431,983 554,237
-------------- --------------
Current Assets:
Cash and cash equivalents..................................... 46,202 26,057
Accounts receivables, net of allowance for uncollectible
accounts of $17,075 and $18,025........................... 106,087 147,787
Other receivables............................................. 48,938 52,158
Inventories................................................... 36,702 36,483
Regulatory assets............................................. 100 10,473
Short-term investments........................................ 108,297 45,111
Other current assets.......................................... 27,525 31,428
-------------- --------------
Total current assets........................................ 373,851 349,497
-------------- --------------
Deferred Charges:
Regulatory assets............................................. 196,245 197,948
Prepaid retirement costs...................................... 39,176 18,273
Other deferred charges........................................ 87,367 33,726
-------------- --------------
Total deferred charges...................................... 322,788 249,947
-------------- --------------
$2,939,849 $2,934,638
============== ==============
|
The accompanying notes are an integral part of these financial statements.
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001
-------------- --------------
(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands)
Capitalization:
Common stockholders' equity:
Common stock...................................................... $ 622,468 $ 625,632
Accumulated other comprehensive loss, net of tax.................. (31,038) (28,996)
Retained earnings................................................. 442,596 415,388
-------------- --------------
Total common stockholders' equity.............................. 1,034,026 1,012,024
Minority interest.................................................... 12,056 11,652
Cumulative preferred stock without mandatory
redemption requirements......................................... 12,800 12,800
Long-term debt....................................................... 953,912 953,884
-------------- --------------
Total capitalization........................................... 2,012,794 1,990,360
-------------- --------------
Current Liabilities:
Short-term debt....................................................... 100,000 35,000
Accounts payable....................................................... 98,628 120,918
Accrued interest and taxes............................................. 54,452 72,022
Other current liabilities.............................................. 67,456 101,697
-------------- --------------
Total current liabilities...................................... 320,536 329,637
-------------- --------------
Deferred Credits:
Accumulated deferred income taxes...................................... 129,706 120,153
Accumulated deferred investment tax credits............................ 43,149 44,714
Regulatory liabilities................................................. 16,275 52,890
Regulatory liabilities related to accumulated deferred income tax...... 14,163 14,163
Accrued postretirement benefit costs................................... 15,154 14,929
Other deferred credits................................................. 388,072 367,792
-------------- --------------
Total deferred credits......................................... 606,519 614,641
-------------- --------------
$2,939,849 $2,934,638
============== ==============
|
The accompanying notes are an integral part of these financial statements.
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
----------------------------------
2002 2001
--------------- ---------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings........................................................ $ 36,106 $ 113,149
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization................................... 51,189 53,083
Other, net...................................................... (23,876) 29,117
Changes in certain assets and liabilities:
Accounts receivables.......................................... 41,700 (42,693)
Other assets.................................................. (9,684) 31,405
Accounts payable.............................................. (22,290) 1,081
Accrued taxes................................................. (17,278) 48,698
Other liabilities............................................. (45) 23,641
--------------- ---------------
Net cash flows provided by operating activities............... 55,822 257,481
--------------- ---------------
Cash Flows From Investing Activities:
Utility plant additions............................................. (127,781) (111,373)
Redemption of short-term investments................................ 45,000 -
Return of principal of PVNGS lessor notes........................... 8,996 8,535
Other............................................................... (6,452) (10,112)
--------------- ---------------
Net cash flows used for investing activities.................. (80,237) (112,950)
--------------- ---------------
Cash Flows From Financing Activities:
Borrowings.......................................................... 65,000 -
Exercise of employee stock options.................................. (3,312) (2,682)
Dividends paid...................................................... (16,723) (15,935)
Other............................................................... (405) (285)
--------------- ---------------
Net cash flows provided by (used for) financing activities.... 44,560 (18,902)
--------------- ---------------
Increase in Cash and Cash Equivalents................................. 20,145 125,629
Beginning of Period................................................... 26,057 107,691
--------------- ---------------
End of Period......................................................... $ 46,202 $233,320
=============== ===============
Supplemental Cash Flow Disclosures:
Interest paid....................................................... $ 28,914 $ 31,382
=============== ===============
Capitalized interest................................................ $ 3,995 $ -
=============== ===============
Income taxes paid, net ............................................. $ 41,784 $ 52,150
=============== ===============
|
The accompanying notes are an integral part of these financial statements.
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands)
Net Earnings...................................... $ 11,157 $49,597 $ 36,106 $113,149
------------ ------------ ------------ ------------
Other Comprehensive Income (Loss),
net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses)
arising during the period................ (3,765) 935 (2,192) (13)
Less reclassification adjustment for
gains included in net income............. (246) (151) (427) (447)
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............... (1,036) (18,699) (196) (8,984)
Less reclassification adjustment for
(gains) losses in net income............. 430 (17,255) 773 (17,255)
------------ ------------ ------------ ------------
Total Other Comprehensive Loss.................... (4,617) (35,170) (2,042) (19,771)
------------ ------------ ------------ ------------
Total Comprehensive Income........................ $6,540 $ 14,427 $ 34,064 $ 93,378
============ ============ ============ ============
|
The accompanying notes are an integral part of these financial statements.
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands, except per share amounts)
Operating Revenues:
Electric...................................... $220,516 $577,730 $424,479 $1,122,324
Gas........................................... 43,968 87,084 153,169 279,020
Unregulated businesses........................ - 1,277 - 1,277
------------ ------------ ------------ ------------
Total operating revenues.................... 264,484 666,091 577,648 1,402,621
------------ ------------ ------------ ------------
Operating Expenses:
Cost of energy sold........................... 122,692 433,841 277,800 930,939
Administrative and general.................... 35,917 38,768 63,742 78,256
Energy production costs....................... 34,202 37,878 69,173 72,903
Depreciation and amortization................. 24,980 23,929 49,753 48,148
Transmission and distribution costs........... 15,451 15,080 31,988 30,357
Taxes, other than income taxes................ 8,045 7,839 16,081 15,056
Income taxes.................................. 2,733 28,209 12,505 69,115
------------ ------------ ------------ ------------
Total operating expenses.................... 244,020 585,544 521,042 1,244,774
------------ ------------ ------------ ------------
Operating income............................ 20,464 80,547 56,606 157,847
------------ ------------ ------------ ------------
Other Income and Deductions:
Other income.................................. 6,321 13,852 19,493 27,229
Other deductions.............................. (1,626) (35,918) (3,752) (44,735)
Income tax (expense) benefit.................. (2,511) 7,478 (6,884) 5,552
------------ ------------ ------------ ------------
Net other income and deductions............. 2,184 (14,588) 8,857 (11,954)
------------ ------------ ------------ ------------
Income before interest charges.............. 22,648 65,959 65,463 145,893
Interest Charges................................ 11,995 16,362 29,956 32,744
------------ ------------ ------------ ------------
Net Earnings Before Preferred Stock Dividends 10,653 49,597 35,507 113,149
Preferred Stock Dividend Requirements........... 147 147 293 293
------------ ------------ ------------ ------------
Net Earnings.................................... $ 10,506 $ 49,450 $ 35,214 $ 112,856
============ ============ ============ ============
|
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001
-------------- --------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service...................................... $2,179,468 $2,118,417
Gas plant in service........................................... 595,397 575,350
Common plant in service and plant held for future use.......... 20,883 45,223
-------------- --------------
2,795,748 2,738,990
Less accumulated depreciation and amortization................. 1,268,873 1,234,629
-------------- --------------
1,526,875 1,504,361
Construction work in progress.................................. 228,965 249,656
Nuclear fuel, net of accumulated amortization of
$19,533 and $16,954........................................ 26,586 26,940
-------------- --------------
Net utility plant............................................ 1,782,426 1,780,957
-------------- --------------
Other Property and Investments:
Other investments.............................................. 431,917 446,784
Non-utility property, net of accumulated depreciation of
$1,580 for December 31, 2001............................... 966 1,784
-------------- --------------
Total other property and investments......................... 432,883 448,568
-------------- --------------
Current Assets:
Cash and cash equivalents...................................... 16,879 14,677
Accounts receivables, net of allowance for uncollectible
accounts of $17,075 and $18,025............................ 106,087 147,787
Other receivables.............................................. 48,642 52,158
Inventories.................................................... 36,702 36,483
Regulatory assets.............................................. 100 10,473
Short-term investments......................................... - 45,111
Other current assets........................................... 17,921 21,477
-------------- --------------
Total current assets......................................... 226,331 328,166
-------------- --------------
Deferred Charges:
Regulatory assets.............................................. 196,245 187,475
Prepaid retirement costs....................................... 39,176 18,273
Other deferred charges......................................... 87,182 44,199
-------------- --------------
Total deferred charges....................................... 322,603 249,947
-------------- --------------
$2,764,243 $2,807,638
============== ==============
|
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001
--------------- ---------------
(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands)
Capitalization:
Common stockholders' equity:
Common stock................................................... $ 195,589 $ 195,589
Additional paid-in capital..................................... 430,043 430,043
Accumulated other comprehensive loss, net of tax............... (28,615) (28,996)
Retained earnings.............................................. 229,741 288,388
--------------- ---------------
Total common stockholders' equity........................... 826,758 885,024
Minority interest................................................. 12,056 11,652
Cumulative preferred stock without mandatory
redemption requirements...................................... 12,800 12,800
Long-term debt.................................................... 953,912 953,884
--------------- ---------------
Total capitalization........................................ 1,805,526 1,863,360
--------------- ---------------
Current Liabilities:
Short-term debt................................................... 100,000 35,000
Intercompany debt................................................. 11,126 -
Accounts payable.................................................. 95,126 120,918
Intercompany accounts payable..................................... 19,259 -
Accrued interest and taxes........................................ 64,267 72,022
Other current liabilities......................................... 67,781 101,697
--------------- ---------------
Total current liabilities................................... 357,559 329,637
--------------- ---------------
Deferred Credits:
Accumulated deferred income taxes................................... 131,606 120,153
Accumulated deferred investment tax credits......................... 43,149 44,714
Regulatory liabilities.............................................. 51,764 52,890
Regulatory liabilities related to accumulated deferred income tax... 14,163 14,163
Accrued postretirement benefit costs................................ 15,154 14,929
Other deferred credits.............................................. 345,3220 367,792
--------------- ---------------
Total deferred credits........................................... 601,158 614,641
--------------- ---------------
$2,764,243 $2,807,638
=============== ===============
|
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
-----------------------------
2002 2001
------------- -------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings......................................................... $ 35,507 $ 113,149
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization.................................... 50,946 53,083
Other, net....................................................... (24,995) 29,117
Changes in certain assets and liabilities:
Accounts receivables........................................... 41,700 (42,693)
Other assets................................................... (9,026) 31,405
Accounts payable............................................... (25,792) 1,081
Accrued taxes.................................................. (6,658) 48,698
Other liabilities.............................................. 23,132 23,641
------------- -------------
Net cash flows provided by operating activities................ 84,814 257,481
------------- -------------
Cash Flows Used for Investing Activities:
Utility plant additions.............................................. (125,078) (115,941)
Redemption of short-term investments................................. 45,000 -
Return of principal of PVNGS lessor notes............................ 8,996 8,535
Other investing...................................................... (2,618) (5,544)
------------- -------------
Net cash flows used for investing activities................... (73,700) (112,950)
------------- -------------
Cash Flows Used for Financing Activities:
Borrowings........................................................... 65,000 -
Exercise of employee stock options................................... - (2,682)
Dividends paid....................................................... (51,450) (15,935)
Other financing...................................................... (405) (285)
Change in intercompany accounts...................................... (22,057) -
------------- -------------
Net cash flows provided by (used by) financing activities...... (8,912) (18,902)
------------- -------------
Increase in Cash and Cash Equivalents.................................. 2,202 125,629
Beginning of Period.................................................... 14,677 107,691
------------- -------------
End of Period.......................................................... $ 16,879 $233,320
============= =============
Supplemental Cash Flow Disclosures:
Interest paid........................................................ $ 30,241 $ 31,382
============= =============
Capitalized interest................................................. $ 3,995 $ -
============= =============
Income taxes paid, net .............................................. $ 31,514 $ 52,150
============= =============
|
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands)
Net Earnings....................................... $10,653 $49,597 $35,507 $113,149
------------ ------------ ------------ ------------
Other Comprehensive Income (Loss),
net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses)
arising during the period.................. (903) 935 231 (13)
Less reclassification adjustment for
gains included in net income............... (246) (151) (427) (447)
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................ (1,036) (20,317) (196) (8,984)
Less reclassification adjustment for
(gains) losses in cash flow hedges......... 430 (15,637) 773 (17,255)
------------ ------------ ------------ ------------
Total Other Comprehensive Income (Loss)............ (1,755) (35,170) 381 (19,771)
------------ ------------ ------------ ------------
Total Comprehensive Income......................... $ 8,898 $ 14,427 $35,888 $ 93,378
============ ============ ============ ============
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The accompanying notes are an integral part of these financial statements.
PNM RESOURCES, INC. AND SUBSIDIARIES
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; 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 June 30, 2002 and December 31, 2001, the consolidated results of their operations for the three and six months ended June 30, 2002 and 2001 and the consolidated statements of cash flows for the six months ended June 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 rules and regulations. Readers of these statements should refer to the Companies' audited consolidated financial statements and notes thereto for the year ended December 31, 2001, which are included on 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 were dividended to the Holding Company pursuant to an order from the New Mexico Public Regulation Commission ("PRC"). The reader 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.
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In the case of contractual obligations of PNM, these obligations are consolidated with the Company 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 Operations. Intersegment purchases from Generation and Trading Operations are priced using internally developed transfer pricing and are not based on market rates. Customer rates for electric service are set by the PRC based on the recovery of the cost of power production and a rate of return that includes certain generation assets that are part of Generation and Trading Operations, among other things.
Gas
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.
In the first quarter of 2001, Generation and Trading Operations procured its gas fuel supply from Gas. Beginning with the second quarter of 2001, Generation and Trading Operations began procuring its gas supply independently of Gas and contracted with Gas for transportation services only.
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
GENERATION AND TRADING OPERATIONS
Generation and Trading Operations serve four principal markets. These include sales to PNM's Utility Operations to cover retail electric demand, sales to firm-requirements wholesale customers, other contracted sales to third parties for a specified amount of capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of time and energy sales made on an hourly basis at fluctuating, spot-market rates. In addition to generation capacity, PNM purchases power in the open market. As of June 30, 2002, the total net generation capacity of facilities owned or leased by the Company 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, the success of any generation expansion and external factors such as the weather. As a result of state and federal regulatory reforms, the public utility industry is undergoing a fundamental change. As this occurs, the electric generation business is transforming into a competitive marketplace. The Company's future results will be impacted by its ability to recover its stranded costs, incurred previously in providing power generation to electric service customers, the market price of electricity and natural gas costs and the costs of transition to an unregulated status. In addition, as a result of deregulation, the Company may face competition from companies with greater financial and other resources. However, as a result of the energy crisis in California, plans for restructuring the industry are undergoing fundamental review. Any reforms that may be made to existing plans for restructuring the industry will also affect the Company's future results.
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summarized financial information by business segment for the three months ended June 30, 2002 and 2001 is as follows:
Utility
----------------------------------- Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2002:
Operating revenues:
External customers............ $140,322 $43,968 $184,290 $80,194 $ 85 $264,569
Intersegment revenues......... 177 470 647 86,012 (86,659) -
Depreciation and amortization.... 8,346 5,076 13,422 10,573 1,222 25,217
Interest income.................. 37 - 37 394 9,299 9,730
Interest charges................. 5,737 3,316 9,053 3,403 2,233 14,689
Income tax expense (benefit)
from continuing operations..... 5,262 (1,393) 3,869 941 763 5,573
Operating income (loss).......... 13,730 (216) 13,514 4,837 1,098 19,449
Segment net income (loss)........ 8,030 (2,127) 5,903 1,513 3,741 11,157
Total assets..................... 771,770 449,695 1,221,465 1,453,900 264,484 2,939,849
Gross property additions......... 13,610 11,035 24,645 31,886 1,830 58,361
2001:
Operating revenues:
External customers............ $136,368 $87,084 $223,452 $441,362 $ 1,277 $666,091
Intersegment revenues......... 177 - 177 83,396 (83,573) -
Depreciation and amortization.... 8,066 5,333 13,399 10,521 9 23,929
Interest income.................. 543 172 715 935 11,274 12,924
Interest charges................. 4,279 2,957 7,236 9,096 30 16,362
Operating income................. 13,514 2,296 15,810 58,694 6,043 80,547
Income tax expense (benefit)
from continuing operations..... 5,256 (380) 4,876 30,439 (14,384) 20,931
Segment net income (loss)........ 8,021 (580) 7,441 46,448 (4,292) 49,597
Total assets..................... 743,780 467,970 1,211,750 1,585,635 276,147 3,073,532
Gross property additions......... 17,065 10,884 27,949 23,916 4,696 56,561
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PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summarized financial information by business segment for the six months ended June 30, 2002 and 2001 is as follows:
Utility
---------------- ---------------- Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2002:
Operating revenues:
External customers............ $275,565 $153,169 $428,734 $148,914 $ 917 $ 578,565
Intersegment revenues......... 354 470 824 167,962 (168,786) -
Depreciation and amortization.... 16,901 10,388 27,289 21,480 1,227 49,996
Interest income.................. 355 81 436 795 20,331 21,562
Interest charges................. 11,572 6,634 18,206 6,871 4,738 29,815
Income tax expense
from continuing operations..... 11,198 4,318 15,516 2,284 1,981 19,781
Operating income................. 28,747 11,877 40,624 10,418 1,094 52,136
Segment net income............... 17,089 6,587 23,676 3,456 8,974 36,106
Total assets..................... 771,770 449,695 1,221,465 1,453,900 264,484 2,939,849
Gross property additions......... 26,466 17,578 44,044 80,431 3,306 127,781
2001:
Operating revenues:
External customers............ $270,714 $279,020 $549,734 $851,610 $ 1,277 $1,402,621
Intersegment revenues......... 354 - 354 164,313 (164,667) -
Depreciation and amortization.... 16,091 10,623 26,714 21,416 18 48,148
Interest income.................. 1,000 342 1,342 1,480 22,315 25,137
Interest charges................. 8,552 5,942 14,494 18,190 60 32,744
Income tax expense (benefit)
from continuing operations..... 12,078 4,689 16,767 65,561 (18,765) 63,563
Operating income (loss).......... 28,040 12,803 40,843 116,800 204 157,847
Segment net income (loss)........ 18,431 7,156 25,587 100,044 (12,482) 113,149
Total assets..................... 743,780 467,970 1,211,750 1,585,635 276,147 3,073,532
Gross property additions......... 28,505 17,458 45,963 59,251 6,159 111,373
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(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 June 30, 2002 was $4.5 million.
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Natural Gas Contracts
Pursuant to a 1997 order issued by the 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 purchased gas adjustment clause ("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 price risk during the 2001-2002 heating season. PNM expended $9.4 million to purchase options that limit the maximum amount PNM would pay for gas during the winter heating season. PNM recovered its actual hedging expenditures as a component of the PGAC during the months of October 2001 through February 2002 in equal allotments of $1.88 million. As winter 2001-2002 gas prices were substantially lower than the previous year, the hedges placed expired unexercised.
PNM also purchased gas options for the 2002-2003 heating season. PNM expended $6.0 million to purchase options that limit the maximum amount PNM would pay for gas during the winter heating season. PNM plans to recover its actual hedging expenditures as a component of the PGAC during the months of October 2002 through February 2003 in equal allotments of $1.2 million.
Electricity Trading Contracts
For the six months ended June 30, 2002, Generation and Trading Operations settled trading contracts for the sale of electricity that generated $20.6 million of electric revenues by delivering 584,800 MWh. The Company purchased $35.9 million or 673,800 MWh of electricity to support these contractual sales and other open market sales opportunities. For the six months ended June 30, 2001, Generation and Trading Operations settled trading contracts for the sale of electricity that generated $37.3 million of electric revenues by delivering 225,000 MWh. The Company purchased $36.2 million or 205,000 MWh of electricity to support these contractual sales and other open market sales opportunities.
As of June 30, 2002, the Company had open trading contract positions to buy $33.3 million and to sell $51.1 million of electricity. At June 30, 2002, the Company had a gross mark-to-market gain (asset position) on these trading contracts of $6.4 million and gross mark-to-market loss (liability position) of $20.7 million, with a net mark-to-market loss (liability position) of $14.3 million. The change in mark-to-market valuation is recognized in earnings each period.
In addition, Generation and Trading Operations enter into forward physical contracts for the sale of the Company's electric capacity in excess of its retail and wholesale firm requirements 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
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Instruments and Hedging Activities," ("SFAS 133"), as amended. The Company 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 June 30, 2002, the Company had open forward positions classified as normal sales of electricity of $18.3 million and normal purchases of electricity of $52.3 million.
Generation and Trading Operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its retail load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases.
Forward Starting Interest Rate Swaps
PNM currently has $182.0 million of tax-exempt bonds outstanding that are callable at a premium in December 2002 and August 2003. PNM intends to refinance these bonds assuming the interest rate of the refinancing does not exceed the current interest rate of the bonds and has hedged the entire planned refinancing. In order to take advantage of current low interest rates, PNM entered into two forward starting interest rate swaps in November and December 2001 and three additional contracts in the first quarter of 2002. PNM designated these swaps as cash flow hedges. The hedged risks associated with these instruments are the changes in cash flows related to general moves in interest rates expected for the refinancing. The swaps effectively cap the interest on the refinancing to 4.9% plus an adjustment for PNM's and the industry's credit rating. PNM's assessment of hedge effectiveness is based on changes in the interest rates and PNM's credit spread. SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transactions affect earnings. Any hedge ineffectiveness is required to be presented in current earnings. There was no material hedge ineffectiveness in the six months ended June 30, 2002.
A forward starting swap does not require any upfront premium and captures changes in the corporate credit component of an investment grade company's interest rate as well as the underlying Treasury benchmark. The five forward interest rate starting swaps have termination dates and notional amounts as follows: one with a termination date of September 17, 2002 for a notional amount of $46.0 million and four with a termination date of May 15, 2003 for a combined notional amount of $136.0 million. There were no fees on the transaction, as they are imbedded in the rates, and the transactions will be cash settled on the mandatory unwind date (strike date), corresponding to the refinancing date of the underlying debt. The settlement will be capitalized as a cost of issuance and amortized over the life of the debt as a yield adjustment.
PNM RESOURCES, INC. AND SUBSIDIARIES
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 June 30 (in thousands, except per share amounts):
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
----------- ----------- ----------- -----------
Basic:
Net Earnings from Continuing Operations.............. $11,157 $49,597 $ 36,106 $113,149
----------- ----------- ----------- -----------
Net Earnings......................................... 11,157 49,597 36,106 113,149
Preferred Stock Dividend Requirements................ 147 147 293 293
----------- ----------- ----------- -----------
Net Earnings Applicable to Common Stock.............. $11,010 $49,450 $ 35,813 $112,856
=========== =========== =========== ===========
Average Number of Common Shares Outstanding.......... 39,118 39,118 39,118 39,118
=========== =========== =========== ===========
Net Earnings per Common Share (Basic)................ $ 0.28 $ 1.26 $ 0.92 $ 2.89
=========== =========== =========== ===========
Diluted:
Net Earnings Applicable to Common Stock
Used in basic calculation.......................... $11,010 $49,450 $ 35,813 $112,856
=========== =========== =========== ===========
Average Number of Common Shares Outstanding.......... 39,118 39,118 39,118 39,118
Diluted effect of common stock equivalents (a)....... 468 848 494 664
----------- ----------- ----------- -----------
Average common and common equivalent shares
Outstanding........................................ 39,586 39,966 39,612 39,782
=========== =========== =========== ===========
Net Earnings per Share of Common Stock (Diluted)..... $ 0.28 $ 1.24 $ 0.90 $ 2.84
=========== =========== =========== ===========
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(a) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money options of 33,462 and 23,785 for the three months ended and the six months ended June 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 $193 million as of June 30, 2002, of which $123 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. In February 2002, PNM broke ground to build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired generating plant in Southern New Mexico. On June 27, 2002, Lordsburg became fully operational and will serve the wholesale power market. Contracts have not
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 are not anticipated to be added to rate base.
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, the Company could be assessed retrospective adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per reactor per incident. Based upon the Company's 10.2% interest in the three PVNGS units, the Company's maximum potential assessment per incident for all three units is approximately $27.0 million, with an annual payment limitation of $3 million per incident. If the funds provided by this retrospective assessment program prove to be insufficient, Congress could impose revenue raising measures on the nuclear industry to pay claims.
Aspects of the federal law referred to above (the "Price-Anderson Act"), which provides for payment of public liability claims in case of a catastrophic accident involving a nuclear power plant are up for renewal in August 2002. While existing nuclear power 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. A renewal bill was passed by the House with unanimous consent on November 27, 2001. The House proposed a change in the annual retrospective premium limit from $10 million to $15 million per reactor per incident. Additionally, the House proposed to amend the maximum potential assessment from $88.1 million to $98.7 million per reactor per incident, taking into account effects of inflation. On March 7, 2002 the Senate approved a Price-Anderson Act amendment as a part of the comprehensive energy bill. The Senate version is substantially the same as the Price-Anderson Act in its current form. 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 Company cannot predict whether or not Congress will renew the Price-Anderson Act or whether or not an increase will be made to the primary financial protection layer. A House-Senate Conference Committee has been formed to resolve the differences between the amendment approved by the House and that approved by the Senate. In the event the comprehensive energy bill does not pass, it is possible that the Price-Anderson 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.
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 January 1, 2002, a substantial portion of which must be applied to stabilization and decontamination. The Company has also secured insurance against portions of the increased cost of generation or purchased power and business interruption resulting from certain accidental outages of any of the three units if the outages exceed 8 weeks. The insurance coverage discussed in this section is subject to certain policy conditions and exclusions. The Company is a member of an industry mutual insurer. This mutual insurer provides both the "all-risk" and increased cost of generation insurance to the Company. In the event of adverse losses experienced by this insurer, the Company is subject to an assessment. The Company's maximum share of any assessment is approximately $4.6 million per year.
PVNGS Decommissioning Funding
The Company has a program for funding its share of decommissioning costs for PVNGS. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. The results of the 2002 decommissioning cost study indicated that the Company's share of the PVNGS decommissioning costs excluding spent fuel disposal would be approximately $201 million. The estimated market value of the trusts at the end of June 30, 2002 was approximately $54 million.
The Company did not provide any additional funding for the six months ended June 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.
The operator of PVNGS has capacity in existing fuel storage pools at PVNGS which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of PVNGS through 2002, and believes it could augment that storage with the new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. The Company currently estimates that it will incur approximately $41.0 million (in 1998 dollars) over the life of PVNGS for its share of the fuel costs related to the on-site interim storage of spent nuclear fuel during the operating life of the plant. The Company accrues these costs as a component of fuel expense, meaning the charges are accrued as the fuel is burned. The operator of PVNGS currently believes that spent fuel storage or disposal methods will be available for use by PVNGS to allow its continued operation beyond 2002.
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Natural Gas Explosion
On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. The Company's investigation indicates that the leak was an isolated incident likely caused by a combination of corrosion and increased pressure. The Company also is cooperating with an investigation of the incident by the PRC's Pipeline Safety Bureau, which issued its report on March 18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the Company by the injured persons along with several claims for property and business interruption damages have been resolved. 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 Western Resources announced that both companies' Boards of Directors approved an agreement under which the Company would acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing.
In July, 2001, the Kansas Corporation Commission ("KCC") issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for an increase of $151 million. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001, in New York state court. On May 10, 2002, the Company filed an Amended Complaint seeking unspecified damages from Western Resources for numerous breaches of contract related to the determination that the split-off required by the agreement was unlawful and required prior approval by the KCC. The Company also seeks unspecified damages for additional breaches of contract because: Western Resources failed to provide the Company with the opportunity to review and comment on information related to the transaction provided by Western Resources to third parties; Western Resources failed to obtain the Company's consent to amend existing employee compensation and benefits plans or create new ones; and Western Resources filed for approval of an alternative debt reduction plan that represents the abandonment of the split-off required by the agreement. In addition, the Company seeks numerous declarations from the court, including that the Company was not obligated to perform because conditions regarding performance were not satisfied; the Company did not breach when it terminated the agreement; and the rate case order constitutes a material adverse effect under the terms of the agreement.
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. However, the Company subsequently received a letter dated May 28, 2002, from counsel for Western Resources purporting to terminate the agreement and demanding payment of a $25 million termination fee, which the Company declined to pay.
On May 30, 2002, Western Resources filed counterclaims against the Company in New York state court alleging breach of contract and fraud. Western Resources alleged that the Company's January 7 letter constituted a withdrawal or adverse modification of the Company's adoption of the agreement or recommendation that its shareholders approve the agreement. As a result, Western Resources claims that the Company is liable for a $25 million termination fee plus costs and expenses (including attorneys fees) incurred in connection with the litigation. Western Resources also claims that the Company committed fraud by not timely disclosing to Western Resources its intentions not to proceed with the transaction and is seeking additional unspecified damages. The Company believes that the counterclaims filed by Western Resources are without merit and intends to vigorously defend itself against them. The Company also intends to vigorously pursue its own complaint.
On July 3, 2002, the Company filed a Motion for Partial Summary Judgment and for Dismissal of Counterclaims and Defenses.
The Company is unable to predict the ultimate outcome of its litigation with Western Resources.
Other
There are various claims and lawsuits pending against the Company and certain of its subsidiaries. The Company is also subject to federal, state and local environmental laws and regulations, and is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with business operations. It is not possible at this time for the Company to determine fully the effect of all litigation on its consolidated financial statements. However, the Company has recorded a liability where the litigation effects can be estimated and where an outcome is considered probable. The Company does not expect that any known lawsuits, environmental costs and commitments will have a material adverse effect on its financial condition or results of operations.
(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
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
have been lawful at the time they occurred. Sources of potential environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes.
The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, the Company records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts).
The Company's recorded estimated minimum liability to remediate its identified sites is $8.8 million. The ultimate cost to clean up the Company's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur.
For the six months ended June 30, 2002 and 2001, the Company spent $0.8 million and $0.5 million, respectively, for remediation. The majority of the June 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) New and Proposed Accounting Standards
Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" ("SFAS 143"). In June 2001, the FASB issued SFAS
143. The statement requires the recognition of a liability for legal obligations
associated with the retirement of a tangible long-lived asset that result from
the acquisition, construction or development and/or the normal operation of a
long-lived asset. The asset retirement obligation must be recognized at its fair
value when incurred. The cost of the asset retirement obligation has to be
capitalized by increasing the carrying amount of the related long-lived asset by
the same amount as the liability. This cost must be expensed using a systematic
and rational method over the related asset's useful life. SFAS 143 is effective
for the Company beginning January 1, 2003. The Company is currently assessing
the impact of SFAS 143 and is unable to predict its impact on the Company's
operating results and financial position at this time.
Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the FASB issued SFAS 144. The statement amends certain requirements of the previously issued pronouncement on asset impairment, SFAS 121. SFAS 144 removes
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
goodwill from the scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a "primary asset" approach for a group of assets and liabilities that represents the unit of accounting to be evaluated for impairment. In addition, SFAS 144 changes the measurement of long-lived assets to be disposed of by sale, as accounted for by Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued operations are no longer measured on a net realizable value basis, and their future operating losses are no longer recognized before they occur. The Company does not believe SFAS 144 will have a material effect on its future operating results or financial position.
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. According to the old policy, 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 02-03 "Recognition and Reporting of Gains and Losses" on Energy Trading Contracts under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." This EITF issue addresses various aspects of the accounting for contracts involved in energy trading and risk management activities. The EITF concluded that all mark-to-market gains and losses on energy trading contracts should be shown net in the income statement whether or not settled physically. The EITF did not reach a consensus and continues to debate whether the recognition of unrealized gains and losses at inception of an energy trading contract is appropriate in the absence of quoted market prices or current market transactions for contracts with similar terms. The EITF also expanded the disclosure requirements for energy trading activities. Implementation of the consensus for recording energy trading activities net is effective for the Company beginning with its 2002 third quarter financial statements. Comparative financial statements for prior periods are required to be reclassified to conform to the EITF's consensus. The Company is currently assessing the impact of implementing EITF Issue No. 02-03 and is unable to predict its effect on the Company's presentation of operating results. 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.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Management's Discussion and Analysis of Financial Condition and Results of Operations for PNM Resources, Inc. (the "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 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 of a material nature are discussed to the extent known and considered relevant.
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; 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 New Mexico Public Regulation Commission ("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 the Company's excess generation capabilities. The benefits of the merchant operations are shared with retail customers based on a negotiated settlement in proportion to capacity owned, expended effort, and risk assumed. Non-regulated assets may be part of the utility company or owned by an affiliate of the utility company, which could be a subsidiary of the holding company. Currently, all non-regulated assets, except Avistar, are part of the utility. Both retail customers and shareholders benefit from this combination.
The Electric and Gas Services strategy is directed at supplying reasonably priced and reliable energy to retail customers through customer-driven operational excellence, 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 50% of its new generation and 70% of its total portfolio to be committed through long-term contracts, including its sales to retail customers. Such growth will be dependent on market developments, and upon the Company's ability to generate funds for the Company's future expansion.
(Intentionally left blank)
RESULTS OF OPERATIONS
Three Months Ended June 30, 2002
Compared to Three Months Ended June 30, 2001
Consolidated
The Company's net earnings available to common shareholders for the three months ended June 30, 2002 were $11.0 million, a 77.7% decrease in net earnings from $49.5 million in 2001. This decrease primarily reflects the slowdown in the wholesale electric market, where both prices and trading activity were lower than the prior year period. Despite the slow-down in the wholesale electricity market, PNM's electric utility operations recorded an operating income growth of 1.6%. 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 for the second quarter in 2001 were affected by certain non-recurring charges; however, there were no non-recurring charges for the second quarter in 2002. 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
June 30,
--------------------------------------------------
2002 2001
------------------------ ------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
----------- ------------ ------------- ----------
(Income)/Expense
Net Earnings Available for Common
Shareholders.................................. $11,010 $ 0.28 $49,450 $ 1.24
----------- ------------ ------------- ----------
Adjustment for Special Gains and Charges
(net of income tax effects):
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............. - - (406) (0.01)
Western Resources acquisition costs............ - - (2,331) (0.06)
----------- ------------ ------------- ----------
Total........................................ - - (13,598) (0.34)
----------- ------------ ------------- ----------
Net Earnings Available For Common-
Shareholders Excluding Special Gains
and Charges................................... $ 11,010 $ 0.28 $63,048 $ 1.58
=========== ============ ============ ==========
|
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.
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 June 30,
-------------------------------------
2002 2001 Variance
---------------- ----------------- ---------------
(In thousands)
Operating revenues:
External customers....................... $140,322 $136,368 $ 3,954
Intersegment revenues.................... 177 177 -
---------------- ----------------- ---------------
Total revenues........................... 140,499 136,545 3,954
---------------- ----------------- ---------------
Cost of energy sold........................ 1,020 1,252 (232)
Intersegment purchases..................... 86,012 83,396 2,616
---------------- ----------------- ---------------
Total cost of energy..................... 87,032 84,648 2,384
---------------- ----------------- ---------------
Gross margin............................... 53,467 51,897 1,570
---------------- ----------------- ---------------
Administrative and other................... 14,144 12,799 1,345
Depreciation and amortization.............. 8,346 8,066 280
Transmission and distribution costs........ 8,805 8,334 471
Taxes other than income taxes.............. 3,205 3,133 72
Income taxes............................... 5,237 6,051 (814)
---------------- ----------------- ---------------
Total non-fuel operating expenses........ 39,737 38,383 1,354
---------------- ----------------- ---------------
Operating income........................... $ 13,730 $ 13,514 $ 216
---------------- ----------------- ---------------
|
Operating revenues increased $4.0 million or 2.9% for the period to $140.5 million. Retail electricity delivery grew 3.1% to 1.83 million MWh in 2002 compared to 1.77 million MWh delivered in the prior year period, resulting in increased revenues of $4.0 million period-over-period. This volume increase was the result of a weather-driven increase in consumption and continued load growth of 3.1%, which is consistent with historical levels. Period over period, customer growth was approximately 2%, also consistent with historical levels.
(Intentionally left blank)
The following table shows electric revenues by customer class and average customers:
Electric Revenues
Three Months Ended
June 30,
2002 2001
------------ ------------
(In thousands)
Residential.................. $45,408 $43,332
Commercial................... 62,867 61,126
Industrial................... 20,792 20,488
Other........................ 11,432 11,599
------------ ------------
$140,499 $136,545
============ ============
Average customers............ 384,000 377,000
============ ============
|
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
Three Months Ended
June 30,
2002 2001
------------ ------------
Residential................... 530,300 506,712
Commercial.................... 827,335 806,003
Industrial.................... 405,571 396,832
Other......................... 62,491 61,667
------------ ------------
1,825,697 1,771,214
============ ============
|
The gross margin, or operating revenues minus cost of energy sold, increased $1.6 million, which reflects the increased energy sales. Electric exclusively purchases power from Generation and Trading at internally 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 $1.4 million or 3.5%. Administrative and other increased $1.3 million or 10.5% due to higher administrative costs allocated from Corporate. Depreciation and amortization increased $0.3 million or 3.5% for the period due to a higher depreciable plant base. Transmission and distribution costs increased $0.5 million or 5.6% primarily due to an increase in overhead line maintenance to enhance system reliability. Income taxes, which include taxes for interest charges, decreased $0.8 million or 13.5% due to the decline in pre-tax income.
Gas
The table below sets forth the operating results for the Gas business segment.
Gas
Three Months Ended June 30,
--------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers........................ $ 43,968 $ 87,084 $ (43,116)
Intersegment revenues..................... 470 - 470
-------------- --------------- ---------------
Total revenues............................ 44,438 87,084 (42,646)
-------------- --------------- ---------------
Total cost of energy...................... 18,922 57,745 (38,823)
-------------- --------------- ---------------
Gross margin................................ 25,516 29,339 (3,823)
-------------- --------------- ---------------
Administrative and other.................... 14,333 13,440 893
Depreciation and amortization............... 5,076 5,333 (257)
Transmission and distribution costs......... 6,594 6,647 (53)
Taxes other than income taxes............... 2,043 2,056 (13)
Income taxes................................ (2,314) (433) (1,881)
-------------- --------------- ---------------
Total non-fuel operating expenses......... 25,732 27,043 (1,311)
-------------- --------------- ---------------
Operating income (loss)..................... $ (216) $ 2,296 $ (2,512)
-------------- --------------- ---------------
|
Operating revenues decreased $42.6 million or 49.0% for the period to $44.4 million, primarily as the result of lower natural gas prices during the second quarter of 2002 as compared to the same period in the previous year and a decrease in gas sales volumes of 13.1%. Despite the volume decline, customer growth was approximately 2%, which is consistent with historical levels. 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
Three Months Ended
June 30,
2002 2001
------------ ------------
(In thousands)
Residential................ $25,618 $44,802
Commercial................. 8,185 12,881
Industrial................. 415 12,381
Transportation*............ 5,134 6,411
Other...................... 5,086 10,609
------------ ------------
$ 44,438 $87,084
============ ============
Average customers.......... 444,000 435,000
============ ============
|
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
Three Months Ended
June 30,
2002 2001
------------ ------------
Residential................... 3,041 3,557
Commercial.................... 1,537 1,466
Industrial.................... 125 1,540
Transportation*............... 14,076 15,223
Other......................... 1,113 1,112
------------ ------------
19,892 22,898
============ ============
|
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold, decreased $3.8 million or 13.0%. This decrease is due mainly to lower consumption of gas for electric generation and a decrease in residential and commercial gas sales volumes due to warmer weather conditions. 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 additional rate relief by year end.
Total non-fuel operating expense decreased $1.3 million or 4.8%. Administrative and other costs increased $0.9 million or 6.6% for the period primarily due to higher administrative costs allocated from Corporate. The increase in the Corporate allocation was partially offset by the absence in 2002 of 2001 consulting expenses related to the analysis of a natural gas line disruption and a decrease in bad debt expense resulting from improved collection levels. Income taxes, which include taxes for interest charges, decreased $1.9 million, due to the decline in pre-tax income.
(Intentionally left blank)
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 June 30,
--------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers.......................... $ 80,194 $441,362 $(361,168)
Intersegment revenues....................... 86,012 83,396 2,616
-------------- --------------- ---------------
Total revenues.............................. 166,206 524,758 (358,552)
-------------- --------------- ---------------
Cost of energy sold........................... 102,750 374,844 (272,094)
Intersegment purchases........................ 647 177 470
-------------- --------------- ---------------
Total cost of energy........................ 103,397 375,021 (271,624)
-------------- --------------- ---------------
Gross margin.................................. 62,809 149,737 (86,928)
-------------- --------------- ---------------
Administrative and other...................... 9,960 8,293 1,667
Energy production costs....................... 33,703 37,304 (3,601)
Depreciation and amortization................. 10,573 10,521 52
Transmission and distribution costs........... 50 100 (50)
Taxes other than income taxes................. 2,796 2,322 474
Income taxes.................................. 890 32,503 (31,613)
-------------- --------------- ---------------
Total non-fuel operating expenses........... 57,972 91,043 (33,071)
-------------- --------------- ---------------
Operating income.............................. $ 4,837 $ 58,694 $ (53,857)
-------------- --------------- ---------------
|
Operating revenues declined $358.6 million or 68.3% for the period to $166.2 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. Average prices in the second quarter were approximately $28 per MWh as opposed to $147 per MWh in the prior year quarter.
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.
Trading volume declines reflect the reduction in trading partners in the wholesale market caused by bankruptcy of certain counterparties, reduced credit quality of firms in the market and firms exiting the wholesale trading market. There are also significant unresolved 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 2.4 million MWh of electricity for the three months ended June 30, 2002, compared to 3.2 million MWh for the same period in 2001.
The following table shows revenues by customer class:
Generation and Trading Revenues By Market
Three Months Ended
June 30,
2002 2001
--------------- -------------
(In thousands)
Intersegment sales........... $ 86,012 $ 83,396
Long-term contract........... 10,562 16,981
Trading*..................... 64,398 424,381
Other........................ 5,234 -
--------------- -------------
$ 166,206 $ 524,758
=============== =============
|
*Includes mark-to-market gains/(losses).
The following table shows sales by customer class:
Generation and Trading Sales By Market
(Megawatt hours)
Three Months Ended
June 30,
2002 2001
--------------- -------------
Intersegment sales........... 1,825,697 1,771,214
Long-term contract........... 227,000 368,894
Trading...................... 2,202,453 2,782,462
--------------- -------------
4,255,150 4,922,570
=============== =============
|
The gross margin, or operating revenues minus cost of energy sold, decreased $86.9 million or 58.1%. Lower margins were created primarily by weak pricing, less price volatility and decreased trading activity. Margins were also impacted by higher coal costs at 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 $33.9 million period-over-period ($6.6 million gain in 2002 versus a $27.3 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 $33.1 million or 36.3%. Administrative and other costs increased $1.7 million or 20.1% due to higher administrative costs allocated from Corporate. Energy production costs decreased $3.6 million or 9.7% for the period primarily due to higher maintenance costs in 2001 at SJGS as a result of an outage. Taxes other than income increased $0.5 million or 20.4% reflecting adjustments recorded in the prior year for favorable audit outcomes by certain tax authorities. Income taxes, which include taxes for interest charges, decreased $31.6 million or 97.3%, 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 $4.7 million for the period to $24.7 million. This increase was primarily due to higher labor resulting from a transfer of employees from operations to Corporate, higher legal and environmental costs due to increased business exposures and outside services related to debt refinancing activities. These increases were partially offset by decreased retirement costs due to higher expected returns on plan assets and a $23.5 million contribution to its plans in January 2002. In addition, the Company had lower bonus expense resulting from lower earnings projections.
Other Non-Operating
Other income decreased $3.0 million or 22.0% due to lower period-over-period returns on investments reflecting current financial market conditions.
Other deductions decreased $34.7 million or 97.2% 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, made 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 $5.6 million for the three months ended June 30, 2002, compared to $20.9 million for the three months ended June 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 June 30, 2002 and 2001 were 33.31% and 29.68%, 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 38.8% in 2001. The decrease in the effective rate was primarily due to adjustments to the Company's prior year tax returns for certain research and development credits related to generating plant additions.
RESULTS OF OPERATIONS
Six Months Ended June 30, 2002
Compared to Six Months Ended June 30, 2001
Consolidated
The Company's net earnings available to common shareholders for the six months ended June 30, 2002 were $35.8 million, a 68.3% decrease in net earnings from $112.9 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 slow-down in the wholesale electricity market, PNM's electric utility operations recorded operating income growth of 2.5%. 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.
Six Months Ended
June 30,
------------------------------------------------------------
2002 2001
---------------------------- ------------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
-------------- ------------- --------------- --------------
(Income)/Expense
Net Earnings Available for Common
Shareholders................................ $ 35,813 $ 0.90 $ 112,856 $ 2.84
-------------- ------------- --------------- --------------
Adjustment for Special Gains and Charges
(net of income tax effects):
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........... - - (5,387) (0.14)
Western Resources acquisition costs.......... - - (2,781) (0.07)
-------------- ------------- -------------- --------------
Total...................................... - - (19,029) (0.48)
-------------- ------------- -------------- --------------
Net Earnings Available For Common-
Shareholders Excluding Special Gains
and Charges................................. $ 35,813 $ 0.90 $ 131,885 $ 3.32
============== ============= ============== ==============
|
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.
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
Six Months Ended June 30,
-------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers..................... $275,565 $270,714 $ 4,851
Intersegment revenues.................. 354 354 -
-------------- --------------- ---------------
Total revenues......................... 275,919 271,068 4,851
-------------- --------------- ---------------
Cost of energy sold...................... 2,212 2,812 (600)
Intersegment purchases................... 167,962 164,313 3,649
-------------- --------------- ---------------
Total cost of energy................... 170,174 167,125 3,049
-------------- --------------- ---------------
Gross margin............................. 105,745 103,943 1,802
-------------- --------------- ---------------
Administrative and other................. 25,148 24,941 207
Depreciation and amortization............ 16,901 16,091 810
Transmission and distribution costs...... 17,317 16,441 876
Taxes other than income taxes............ 6,378 5,660 718
Income taxes............................. 11,254 12,770 (1,516)
-------------- --------------- ---------------
Total non-fuel operating expenses...... 76,998 75,903 1,095
-------------- --------------- ---------------
Operating income......................... $ 28,747 $ 28,040 $ 707
-------------- --------------- ---------------
|
Operating revenues increased $4.9 million or 1.8% for the period to $275.9 million. Retail electricity delivery grew 2.2% to 3.6 million MWh in 2002 compared to 3.5 million MWh delivered in the prior year period, resulting in increased revenues of $4.8 million year-over-year. This volume increase was the result of a weather-driven increase in consumption and continued load growth of 2.2%. Period over period, customer growth was 2%.
(Intentionally left blank)
The following table shows electric revenues by customer class and average customers:
Electric Revenues
Six Months Ended
June 30,
2002 2001
------------- -------------
(In thousands)
Residential................ $96,418 $92,843
Commercial................. 117,582 114,950
Industrial................. 40,420 40,325
Other...................... 21,499 22,950
------------- -------------
$275,919 $271,068
============= =============
Average customers 383,000 376,000
============= =============
|
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
Six Months Ended
June 30,
2002 2001
------------- -------------
Residential............... 1,123,413 1,083,085
Commercial................ 1,534,477 1,515,027
Industrial................ 797,917 784,967
Other..................... 109,365 106,700
------------- -------------
3,565,172 3,489,779
============= =============
|
The gross margin, or operating revenues minus cost of energy sold, increased $1.8 million or 1.7%, 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 1.4%. Administrative and other costs were flat for the period. Lower bad debt expense as a result of collection improvements and the absence of the bankruptcy of a significant customer in 2001 were offset by higher administrative cost allocated from Corporate. Depreciation and amortization increased $0.8 million or 5.0% for the period due to a higher depreciable plant base. Transmission and distribution costs increased $0.9 million or 5.3% primarily due to an increase in overhead line maintenance focused on improving overall system reliability. Taxes other than income increased $0.7 million or 12.7% primarily reflecting the absence of favorable audit outcomes by certain tax authorities in 2001. Income taxes, which include taxes associated with interest charges, decreased $1.5 million or 11.9% due to lower pre-tax income.
Gas
The table below sets forth the operating results for the Gas business segment.
Gas
Six Months Ended June 30,
-------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers............................. $153,169 $279,020 $(125,851)
Intersegment revenues.......................... 470 - 470
-------------- --------------- ---------------
Total revenues................................. 153,639 279,020 (125,381)
-------------- --------------- ---------------
Total cost of energy........................... 83,671 206,217 (122,546)
-------------- --------------- ---------------
Gross margin..................................... 69,968 72,803 (2,835)
-------------- --------------- ---------------
Administrative and other......................... 25,657 27,527 (1,870)
Depreciation and amortization.................... 10,388 10,623 (235)
Transmission and distribution costs.............. 14,524 13,703 821
Taxes other than income taxes.................... 4,086 3,652 434
Income taxes..................................... 3,436 4,495 (1,059)
-------------- --------------- ---------------
Total non-fuel operating expenses.............. 58,091 60,000 (1,909)
-------------- --------------- ---------------
Operating income................................. $ 11,877 $ 12,803 $ (926)
-------------- --------------- ---------------
|
Operating revenues decreased $125.4 million or 44.9% for the period to $153.6 million, primarily as the result of lower natural gas prices during the second quarter of 2002 as compared to the same period in the previous year and a decrease in gas sales volumes of 8.5%. Despite the volume decline, customer growth was approximately 2%. 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
Six Months Ended
June 30,
2002 2001
-------------- -------------
(In thousands)
Residential............... $97,724 $166,396
Commercial................ 30,590 49,675
Industrial................ 1,064 25,918
Transportation*........... 8,745 10,413
Other..................... 15,516 26,618
-------------- -------------
$153,639 $279,020
============== =============
Average customers......... 444,000 435,000
============== =============
|
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
Six Months Ended
June 30,
2002 2001
-------------- -------------
Residential 16,500 16,020
Commercial............... 6,564 5,691
Industrial............... 296 3,520
Transportation*.......... 21,473 24,401
Other.................... 3,104 2,777
-------------- -------------
47,937 52,409
============== =============
|
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold, decreased $2.8 million or 3.9%. This decrease is due mainly to lower consumption of gas for electric generation partially offset by a 2% growth in customer base.
Total non-fuel operating expenses decreased $1.9 million or 3.2%. Administrative and other costs decreased $1.9 million or 6.8%. This decrease is primarily due to a lower bad debt expense as a result of losses from a bankruptcy of a significant customer in 2001. This cost improvement was largely offset by higher allocated Corporate administrative costs. Transmission and distribution costs increased $0.8 million or 6.0% primarily due to lower capital activity in 2002. Income taxes, which include income taxes for interest charges, decreased $1.1 million or 23.6% due to lower pre-tax income.
(Intentionally left blank)
Generation and Trading Operations
The table below sets forth the operating results for the Generation and
Trading business segment.
Generation and Trading
Six Months Ended June 30,
-------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers............................. $148,914 $851,610 $(702,696)
Intersegment revenues.......................... 167,962 164,313 3,649
-------------- --------------- ---------------
Total revenues................................. 316,876 1,015,923 (699,047)
-------------- --------------- ---------------
Cost of energy sold.............................. 191,917 721,910 (529,993)
Intersegment purchases........................... 824 354 470
-------------- --------------- ---------------
Total cost of energy........................... 192,741 722,264 (529,523)
-------------- --------------- ---------------
Gross margin..................................... 124,135 293,659 (169,524)
-------------- --------------- ---------------
Administrative and other......................... 16,218 14,778 1,440
Energy production costs.......................... 67,914 71,588 (3,674)
Depreciation and amortization.................... 21,480 21,416 64
Transmission and distribution costs.............. 145 213 (68)
Taxes other than income taxes.................... 5,616 4,243 1,373
Income taxes..................................... 2,344 64,621 (62,277)
-------------- --------------- ---------------
Total non-fuel operating expenses.............. 113,717 176,859 (63,142)
-------------- --------------- ---------------
Operating income................................. $ 10,418 $116,800 $(106,382)
-------------- --------------- ---------------
|
Operating revenues declined $699.0 million or 68.8% for the period to $316.9 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 $26 per MWh in 2002 versus $139 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 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 4.8 million MWh of electricity for the six months ended June 30, 2002, compared to 6.3 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.
The following table shows revenues by customer class:
Generation and Trading Revenues By Market
Six Months Ended
June 30,
2002 2001
-------------- --------------
(In thousands)
Intersegment sales............ $ 167,962 $ 164,313
Long-term contract............ 24,899 45,795
Trading*...................... 115,874 802,432
Other......................... 8,141 3,383
-------------- --------------
$ 316,876 $1,015,923
============== ==============
|
*Includes mark-to-market gains/(losses).
The following table shows sales by customer class:
Generation and Trading Sales By Market
(Megawatt hours)
Six Months Ended
June 30,
2002 2001
-------------- --------------
Intersegment sales........... 3,565,172 3,489,779
Long-term contract........... 508,153 846,947
Trading...................... 4,262,695 5,462,540
-------------- --------------
8,336,020 9,799,266
============== ==============
|
The gross margin, or operating revenues minus cost of energy sold, decreased $169.5 million or 57.7%. 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 $42.3 million period-over-period ($16.1 million gain in 2002 versus $26.2 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 $63.1 million or 35.7%. Administrative and other costs increased $1.4 million or 9.7% for the period. This increase is primarily due to higher corporate allocations and an adjustment to prior year SJGS participant billings (the Company is the operator of SJGS and
shares costs with other owners). These cost increases were partially offset by lower costs resulting from increased capital activity for generation expansion. Energy production costs also decreased $3.7 million or 5.1% for the period reflecting the benefits of the acceleration into 2001 of a planned outage at SJGS offset by a planned and unplanned outage at the Company's Four Corners facility. Taxes other than income increased $1.4 million or 32.4% 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 $62.3 million or 96.4% due to a decline in pre-tax income.
Corporate
Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, decreased $4.7 million for the period to $41.6 million. This decrease was primarily due to lower retiree benefits expense and lower bonus expense in the current year resulting from lower earnings projections.
Other Non-Operating
Other income decreased by $4.2 million or 15.5% reflecting lower year-over-year returns on investments reflecting market conditions.
Other deductions decreased $43.8 million or 97.9% 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 $19.8 million for the six months ended June 30, 2002, compared to $63.6 million for the six months ended June 30, 2001. The impact of lower earnings in 2002 contributed to the difference. The Company's effective income tax rates for the six months ended June 30, 2002 and 2001 were 35.39% and 35.97%, 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, where 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 38.9% in 2001. The decrease in the effective rate was primarily due to adjustments to the Company's prior year tax returns for certain research and development credits.
FUTURE EXPECTATIONS
Continued weakness in the wholesale power market has caused the Company to reduce its 2002 earnings estimate. 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 Operations.
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 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 25% reduction in wholesale sales for the Company compared to the first half of 2001.
Other contributing factors include increased coal costs and lower earnings in the gas utility business as a result of a mild spring.
To preserve the Company's strong financial position, management intends to control expenses and limit capital expenditures. Construction expenditures in 2002, originally budgeted at $391 million, have been reduced by $111 million to $280 million for the year. Planned construction expenditures through 2003 have been reduced in total by over $400 million.
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 enumerated above.
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2002, the Company had cash and short-term investments of $154.5 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 six months ended June 30, 2002 was $55.8 million compared to cash provided by operating activities of $257.5 million for the six months ended June 30, 2001. This decrease was primarily the result of current wholesale market conditions. Also contributing to the decrease was the Company's $23.5 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 $80.2 million in 2002 compared to $113.0 million in 2001. Cash used for investing activities includes construction expenditures for new generating plants of $82.6 million in 2002, which did not occur 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.
Cash generated by financing activities was $44.6 million in 2002 compared to $18.9 million of cash used in 2001. Financing activities in 2002 were primarily short-term borrowings of $65 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 the pension and other postretirement benefit plans. The effect of the change in expected rate of return and additional cash contribution has a decrease in pension and other benefits expense for the six months ended June 30, 2002.
Capital Requirements
Total capital requirements include construction expenditures as well as other major capital requirements and cash dividend requirements for both common and preferred stock. The main focus of the Company's construction program is upgrading generation systems 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. 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 $193 million as of June 30, 2002 of which $123.0 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. In February 2002, PNM broke ground to build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired generating plant in Southern New Mexico. On June 27, 2002, Lordsburg became fully operational and will serve 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 are not anticipated to be added to rate base.
The Company's construction expenditures for 2001 were entirely funded through cash generated from operations. In the first six 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
In July 2002, PNM had $200 million of available liquidity arrangements, consisting of $150 million from an unsecured revolving credit facility ("Credit Facility"), $30 million in local lines of credit and $20 million from a reciprocal borrowing agreement with the Holding Company. The Credit Facility will expire in March 2003. There were $100 million in borrowings against the credit facility as of August 1, 2002. In addition, the Holding Company has a $20 million reciprocal borrowing agreement with PNM and $25 million in local lines of credit.
The Company's ability, 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 ("Moody's") and Standard and Poor's ("S&P") and positive by Fitch Ratings ("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, ultimately leading the Company to terminate the transaction in January 2002, S&P, Moody's and Fitch removed the Company from negative credit watch. The Company is committed to maintaining its investment grade. S&P currently rates PNM's senior unsecured notes ("SUNs") and its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its preferred stock "BB". Moody's rates PNM's SUNs and senior unsecured pollution control revenue bonds "Baa3"; and preferred stock "Ba1". The EIP senior secured debt is also rated "Ba1". Fitch rates PNM's SUNs and senior unsecured pollution control revenue bonds "BBB-," PNM's EIP lease obligation "BB+" and PNM's preferred stock "BB-." Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it may be subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.
Long-term Obligations and Commitments
The following table shows PNM's long-term debt and operating leases as of June 30, 2002. As of June 30, 2002, PNM Resources, Inc. and Subsidiaries have no long-term obligations except those acquired through consolidation with PNM.
Payments Due
-----------------------------------------------------------------------
(In thousands)
Less than
Contractual 1 year 2-3 years 4-5 years After 5
Obligations Total years
------------- ----------- ----------- ----------- -------------
Long-Term Debt.................... $ 953,912 $ - $ - $268,420 $ 685,492
Operating Leases.................. 516,906 32,572 67,022 70,764 346,548
------------- ----------- ----------- ----------- -------------
Total Contractual Cash
Obligations.................... $1,470,818 $32,572 $67,022 $339,184 $1,032,040
============= =========== =========== =========== =============
|
PNM leases interests in Units 1 and 2 of PVNGS, certain transmission facilities, office buildings and other equipment under operating leases. The lease expense for PVNGS is $66.3 million per year over base lease terms expiring in 2015 and 2016. In 1998, PNM established PVNGS Capital Trust ("Capital Trust") for the purpose of acquiring all the debt underlying the PVNGS leases. PNM consolidates Capital Trust in its consolidated financial statements. The purchase was funded with the proceeds from the issuance of $435 million of SUNs, which were loaned to Capital Trust. Capital Trust then acquired and now holds the debt component of the PVNGS leases. For legal and regulatory reasons, the PVNGS lease payment continues to be recorded and paid gross with the debt component of the payment returned to PNM via Capital Trust. As a result, the net cash outflows for the PVNGS lease payment were $12.4 million as of 2002. The table above reflects the net lease payment.
PNM's other significant operating lease obligations include the Eastern Interconnect Project ("EIP"), a transmission line with annual lease payments of $7.3 million, and a power purchase agreement for the entire output of Delta Person Generating Station ("Delta"), a gas-fired generating plant in Albuquerque, New Mexico with imputed annual lease payments of $6.0 million.
The Company's off-balance sheet obligations are limited to PNM's operating leases and certain financial instruments related to the purchase and sale of energy (see below). The present value of PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and the Delta PPA was $224 million as of June 30, 2002.
PNM has entered various long-term power purchase agreements obligating it to make 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 June 30, 2002 included open contract positions to buy $33.3 million of electricity and to sell $51.1 million of electricity. In addition, PNM had open forward positions classified as normal sales of electricity under the derivative accounting rules of $18.3 million and normal purchases of electricity of $52.3 million.
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.
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 the Company recovers 100% of its cost of gas.
Contingent Provisions of Certain Obligations
The Holding Company and PNM have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. The Holding Company and/or PNM could be required to provide security, immediately pay outstanding obligations or be prevented from drawing on unused capacity under certain credit agreements, if the contingent requirements were to be triggered. The most significant consequences resulting from these contingent requirements are detailed in the discussion below.
PNM's master purchase agreement for the procurement of gas for its 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 System Power Pool ("WSPP") contains a contingent requirement that could require PNM to provide security if its' debt were to fall below the investment grade rating. The WSPP agreement also contains a contingent requirement, commonly called a material adverse change ("MAC") provision, which could require PNM to provide security if a material adverse change in its financial condition or operations were to occur.
PNM's committed Credit Facility contains a MAC provision which if triggered could prevent PNM from drawing on its unused capacity under the Credit Facility. In addition, the Credit Facility contains a contingent requirement that requires PNM to maintain a debt-to-capital ratio of less than 70%. If PNM's debt-to-capital ratio were to exceed 70%, PNM could be required to repay all borrowings under the Credit Facility, be prevented from drawing on the unused capacity under the Credit Facility, and be required to provide security for all outstanding letters of credit issued under the Credit Facility. At June 30, 2002, the Company had $8.5 million of letters of credit outstanding.
If a contingent requirement were to be triggered under the Credit Facility resulting in an acceleration of the outstanding loans under the Credit Facility, a cross-default provision in the PVNGS leases could occur if the accelerated amount is not paid. If a cross-default provision is triggered, the lessors have the ability to accelerate their rights under the leases, including acceleration of all future lease payments.
Planned Financing Activities
PNM has $268.4 million of long-term debt that matures in August 2005. All other long-term debt matures in 2016 or later. The Company could enter into other long-term financings for the purpose of strengthening its balance sheet, funding growth and reducing its cost of capital. The Company continues to evaluate its investment and debt retirement options to optimize its financing strategy and earnings potential. No additional first mortgage bonds may be issued under PNM's mortgage. The amount of SUNs that may be issued is not limited by the SUNs indenture. However, debt-to-capital requirements in certain of PNM's financial instruments would ultimately limit the amount of SUNs PNM would issue.
PNM currently has $182.0 million of tax-exempt bonds outstanding that are callable at a premium in December 2002 and August 2003. PNM intends to refinance these bonds assuming the interest rate of the refinancing does not exceed the current interest rate of the bonds and has hedged the entire planned refinancing. In order to take advantage of current low interest rates, PNM entered into two forward starting interest rate swaps in November and December 2001 and three additional contracts during the first quarter of 2002. PNM designated these swaps as cash flow hedges. The hedged risks associated with these instruments are the changes in cash flows related to general moves in interest rates expected for the refinancing. The swaps effectively cap the interest rate on the refinancing to 4.9% plus an adjustment for PNM's and the industry's credit rating. PNM's assessment of hedge effectiveness is based on changes in the hedge interest rates. The derivative accounting rules, as amended, provide that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transactions affect earnings. Any hedge ineffectiveness is required to be presented in current earnings. There was no material hedge ineffectiveness in the six months ended June 30, 2002.
A forward starting swap does not require any upfront premium and captures changes in the corporate credit component of an investment grade company's interest rate as well as the underlying Treasury benchmark. The five forward interest rate starting swaps have termination dates and notional amounts as follows: one with a termination date of September 17, 2002 for a notional amount of $46.0 million and four with a termination date of May 15, 2003 for a combined notional amount of $136.0 million. There were no fees on the transaction, as they are imbedded in the rates, and the transaction is cash settled on the mandatory unwind date (strike date), corresponding to the refinancing date of the underlying debt. The settlement will be capitalized as a cost of issuance and amortized over the life of the debt as a yield adjustment.
Dividends
The Company's Board of Directors regularly reviews the Company's dividend policy. The declaration of common dividends is dependent upon a number of factors including the ability of the Company's subsidiaries to pay dividends. Currently, PNM is the 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, which cause its debt rating to go below investment grade; and PNM cannot pay dividends in any year, as determined on a rolling four-quarter basis, in excess of net earnings without prior PRC approval. Additionally, PNM has various financial covenants, which limit the transfer of assets, through dividends or other means.
In addition, the ability of the Company to declare dividends is dependent upon the extent to which cash flows will support dividends, the availability of retained earnings, its financial circumstances and performance, the PRC's decisions in various regulatory cases currently pending and which may be docketed in the future, the effect of deregulating generation markets and market economic conditions generally. The ability to recover stranded costs in deregulation (as amended), conditions imposed on holding company formation, future growth plans and the related capital requirements and standard business considerations may also affect the Company's ability to pay dividends.
Consistent with the PRC's holding company order, PNM paid dividends of $127.0 million to the 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 Company's Board of Directors approved a 10 percent increase in the common stock dividend. The increase raises the quarterly dividend to $0.22 per share, for an indicated annual dividend of $0.88 per share. The Company's Board of Directors approved a policy for future dividend increases in the range of 8 to 10 percent annually, targeting a payout of between 50 to 60 percent of regulated earnings. The Company believes that this target is consistent with the Company's expectation of future operating cash flows and the cash needs of its planned increase in generating capacity.
Capital Structure
The Company's capitalization, including current maturities of long-term debt, at June 30, 2002 and December 31, 2001 is shown below:
June 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 June 30, 2002 and $225 million as of December 31, 2001.
OTHER ISSUES FACING THE COMPANY
RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY
In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delay the original implementation dates by approximately five years, including the requirement for
corporate separation of supply service and energy-related service assets from distribution and transmission service assets. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. The Company is unable to predict the form its further restructuring will take under the delayed implementation of customer choice. In addition, the Restructuring Act, as amended, recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers.
The amendments to the Restructuring Act required that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of supply service and energy-related service assets from distribution and transmission service assets, by July 1, 2001. In addition, the amendments allow utilities to engage in unregulated power generation business activities until corporate separation is implemented.
On December 31, 2001, the Company implemented the holding company structure without corporate separation of supply service and energy-related services assets from distribution and transmission services assets. This structure provides for a holding company whose current holdings will be PNM, Avistar and other inactive unregulated subsidiaries. This was effected through the share exchange between PNM shareholders and the Holding Company, PNM Resources Inc. Avistar and most of the inactive unregulated subsidiaries became wholly-owned subsidiaries of the Holding Company in January 2002. The transfer of certain corporate related assets to the Holding Company also occurred in January 2002. There are no current plans to provide the Holding Company with significant debt financing.
The 2002 session of the New Mexico Legislature resulted in enactment of tax measures favorable to the construction of merchant generating plants and plants fueled by renewable resources. The new laws provide authority for all local governments in the state to issue industrial revenue bonds for merchant generating plants smaller than 300 MW. The bonds provide exemptions from property taxes. Also enacted into law was a 5% investment tax credit for merchant generating plants smaller than 300 MW; tax credits for qualified generators using renewable resources; and an exemption from gross receipts tax for the cost of certain wind generation equipment.
There is a growing concern in New Mexico about the use of water for merchant power plants, due to the increased activity in building these plants in the state, which has an arid climate. The availability of sufficient water supplies to meet all the needs of the state, including growth, is a major issue. 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.
On April 25, 2002, by a vote of 88-11, the U.S. Senate passed amendments to HR 4, the "Energy Policy Act of 2002". The Senate version contains provisions directly applicable to the electric industry, many of which were not contained in the House version of HR 4. As adopted by the Senate, HR 4 contains provisions
revising FERC authority over utility mergers; provides direction to the FERC regarding the use of market-based rates; provides for possible refunds dating from the date of a complaint rather than the current 60 day waiting period; provides for a reliability organization to establish standards subject to 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 HR 4 will be the subject of conference committee discussions later this year. The Company is unable to predict what form energy legislation will take if agreement is reached between the House and the Senate, if energy legislation will be passed or if it will be signed by the President if passed. Included in the debate over energy legislation are drilling in the Arctic National Wildlife Refuge and automobile fuel efficiency requirements.
The Company along with other Southwest transmission owners formed WestConnect RTO, LLC ("WestConnect") a for-profit transmission company and made a filing on October 16, 2001 with the FERC. WestConnect is the only remaining Regional Transmission Organization ("RTO") still proposing a transmission asset owning company form of governance. However, WestConnect allows for, but does not require a member to transfer its transmission assets. WestConnect is awaiting a FERC order on its formation.
To remedy what 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 Commission 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 FERC rulemakings 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.
RECOVERY OF CERTAIN COSTS UNDER THE RESTRUCTURING ACT
Stranded Costs
The Restructuring Act, as amended, recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers. These stranded costs represent all costs associated with generation-related assets, currently in rates, in excess of the expected competitive market price over the life of those assets and include plant decommissioning costs, regulatory assets, and lease and lease-related costs. Utilities will be allowed to recover no less than 50% of stranded costs through a non-bypassable charge on all customer bills for five years after implementation of customer choice. The PRC could authorize a utility to recover up to 100% of its stranded costs if the PRC finds that recovery of more than 50%: (i) is in the public interest; (ii) is necessary to maintain the financial integrity of the public utility; (iii) is necessary to continue adequate and reliable service; and (iv) will not cause an increase in rates to residential or small business customers during the transition period. The Restructuring Act, as amended, also allows for the recovery of nuclear decommissioning costs by means of a separate wires charge over the life of the underlying generation assets (see Nuclear Regulatory Commission Prefunding below).
The calculation of stranded costs is subject to a number of highly sensitive assumptions, including the date of open access, appropriate discount rates and projected market prices, among others. The Restructuring Act, as amended, requires the Company to file a transition plan, which includes provisions for the recovery of stranded costs, and other expenses associated with the transition to a competitive market no later than January 1, 2005. The Company is unable to predict the amount of stranded costs that it may seek to recover at that time. The Company's previous proposal to recover stranded costs under the original customer choice implementation dates would not accurately represent the Company's expected stranded costs under the amended implementation dates of the Restructuring Act.
Approximately $141 million of costs associated with the power supply and energy services businesses under the Restructuring Act were established as regulatory assets. Because of the Company's belief that recovery is probable, these assets continue to be classified as regulatory assets, although the Company has discontinued the use of accounting for rate regulated activities. The amendments to the Restructuring Act provide the opportunity for amortization of coal mine decommissioning costs currently estimated at approximately $100 million. The Company intends to seek recovery of these costs in its next rate case filing and believes that the costs are fully recoverable. The Company believes that any remaining portion of the regulatory assets will be fully recovered in future rates, including through a non-bypassable wires charge.
The Company believes that the Restructuring Act, as amended, if properly applied, provides an opportunity for recovery of a reasonable amount of stranded costs should such costs exist at the time of separation. If regulatory orders do not provide for a reasonable recovery, the Company is prepared to vigorously pursue judicial remedies. The PRC will make a determination and quantification of stranded cost recovery prior to implementation of restructuring. The determination may have an impact on the recoverability of the related assets and may have a material effect on the future financial results and position of the Company.
Transition Cost Recovery
In addition, the Restructuring Act, as amended, authorizes utilities to recover in full any prudent and reasonable costs incurred in implementing full open access ("transition costs"). These transition costs are currently scheduled to be recovered from 2007 through 2012 by means of a separate wires charge. The PRC may extend this date by up to one year. The Company may seek to recover transition costs already incurred in future rate cases that may occur prior to open access. The Company is unable to predict the amount of transition costs it may incur. To date, the Company has capitalized $24.8 million of expenditures that meet the Restructuring Act's definition of transition costs. Transition costs for which the Company will seek recovery include professional fees, financing costs, consents relating to the transfer of assets, management information system changes including billing system changes and public and customer education and communications. These costs will be amortized over the recovery period to match related revenues. The Company intends to vigorously pursue remedies available to it should the PRC disallow recovery of reasonable transition costs. Costs not recoverable will be expensed when incurred unless these costs are otherwise permitted to be capitalized under current and future accounting rules. Depending on the amount of non-recoverable transition costs, if any, the resulting charge to earnings may have a material effect on the future financial results and position of the Company.
Nuclear Regulatory Commission Prefunding
Pursuant to NRC rules on financial assurance requirements for the decommissioning of nuclear power plants, the Company has a program for funding its share of decommissioning costs for PVNGS through a sinking fund mechanism. The NRC rules on financial assurance became effective on November 23, 1998. The amended rules provide that a licensee may use an external sinking fund as the exclusive financial assurance mechanism if the licensee recovers estimated decommissioning costs through cost of service rates or a "non-bypassable charge". Other mechanisms are prescribed, such as prepayment, surety methods, insurance and other guarantees, to the extent that the requirements for exclusive reliance on the fund mechanism are not met.
The Restructuring Act, as amended, allows for the recoverability of 50% up to 100% of stranded costs including nuclear decommissioning costs. The results of the 1998 triannual decommissioning cost study indicated that PNM's share of the PVNGS decommissioning costs excluding spent fuel disposal would be approximately $201 million. The Restructuring Act, as amended, specifically identifies nuclear decommissioning costs as eligible for separate recovery over a longer period of time than other stranded costs if the PRC determines a separate recovery mechanism to be in the public interest. In addition, the Restructuring Act, as amended, states that it does not require the PRC to issue any order which would result in loss of eligibility to exclusively use external sinking fund methods for decommissioning obligations pursuant to federal regulations. When final determination of stranded cost recovery is made and if the Company is unable to meet the requirements of the NRC rules permitting the use of an external sinking fund because it is unable to recover all of its estimated decommissioning costs through a non-bypassable charge, the Company may have to pre-fund or find a similarly capital intensive means to meet the NRC rules. There can be no assurance that such an event will not negatively affect the funding of the Company's growth plans.
MERCHANT PLANT FILING
Senate Bill ("SB") 266, enacted by the 2001 session of the New Mexico legislature, allowed public utilities to "invest in, construct, acquire or operate" a generating plant not intended to provide retail electric service, free of certain otherwise applicable regulatory requirements contained in the Public Utility Act. By order entered on March 27, 2001, the PRC found that these provisions of SB 266 raised issues such as cost allocations for ratemaking, revenue allocations for off-system sales, how the Commission can ensure the utility will meet its duty to provide service when the utility invests in such generating plant, how that plant will be financed and how transactions between regulated services and merchant plants will be conducted. The Company has filed a pleading addressing these issues and testimony in response to interested parties' requests. A hearing initially scheduled for June 2002, was vacated and no new procedural schedule has yet been established.
In November 2001, the Company began settlement negotiations with the PRC's utility staff and intervenors related to these PRC proceedings in order to resolve a number of matters. In addition to the issues being examined in the Company's merchant plant filing, discussions have included the future framework for restructuring the electric industry in New Mexico under the Restructuring Act, and a future retail electric rate path. The negotiations include the potential implementation and effective date of rates that would replace those approved under the rate freeze stipulation that remains in effect until January 1, 2003.
The Company is currently unable to predict the impact these proceedings may have on its plans to expand its generating capacity and other operations.
WESTERN UNITED STATES WHOLESALE POWER MARKET
A significant portion of the Company's earnings in 2001 was derived from the Company's wholesale power trading operations, which benefited from strong demand and high wholesale prices in the Western United States. These market conditions were 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, although the turmoil in the western markets was not limited to California. However, over the last twelve 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.
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 FERC orders 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 will take effect October 1, 2002, raising the price cap to $250 per MWh. This 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 and Pacific Northwest Refund Proceedings
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 the Company participated, was ultimately unsuccessful, but the administrative law judge called in his recommendation to the FERC for an evidentiary hearing to resolve the dispute, suggesting that refunds were due; however, the estimated refunds were significantly lower than demanded by California, and in most instances, were offset by the amounts due suppliers from the Cal PX and Cal ISO. California had demanded refunds of approximately $9 billion from power suppliers. On July 25, 2001, acting on the recommendation of the administrative law judge, the FERC ordered an expedited fact-finding hearing to evaluate refunds for spot market transactions in California. The FERC also ordered a preliminary hearing to determine whether refunds were due resulting from wholesale sales into the Pacific Northwest. The Pacific Northwest matter was heard by an administrative law judge whose recommended decision declined to order refunds resulting from sales into the Pacific Northwest, but the FERC has not yet acted on this recommended decision. The hearing on potential California refund obligations has not yet been completed and a recommended decision is not anticipated until the second half of 2002. The Company is unable to predict the ultimate outcome of these FERC proceedings, or whether the Company will be directed to make any refunds as the result of a FERC order.
FERC Investigation of "Enron-Like" Trading Practices
The FERC has also initiated a market manipulation investigation, partially in response to the Enron bankruptcy filing 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. The Company 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, the Company denied that it had engaged in activities such as those identified in Enron's memos and also denied engaging in "wash" transactions. Where appropriate, the Company's responses addressed any arguable similarities between any of its trading activities and those under investigation by the FERC. The Company cannot predict the outcome of this investigation.
California Power Exchange Bankruptcy
In 2001, approximately $2 million in wholesale power sales by the Company were made directly to the Cal PX, which was the main market for the purchase and sale of electricity in the state in the beginning of 2001, or the Cal ISO, which manages the state's electricity transmission network. In January and February 2001, SCE and PG&E, major purchasers of power from the Cal PX and ISO, defaulted on payments due the Cal PX for power purchased from the Cal PX in 2000. These defaults caused the Cal PX to seek bankruptcy protection. PG&E subsequently also sought bankruptcy protection. The Company has filed its proofs of claims in the Cal PX and PG&E bankruptcy proceedings. Total amounts due the Company from the Cal PX or Cal ISO for power sold to them in 2000 and 2001 total approximately $7 million. The Company has provided allowances for the total amount due from the Cal PX and Cal ISO.
Prior to its bankruptcy filing, the Cal PX undertook to charge back the defaults of SCE and PG&E to other market participants, in proportion to their participation in the markets. The Company was invoiced for $2.3 million as its proportionate share under the Cal PX tariff. The Company, as well as a number of power marketers and generators, filed complaints with the FERC to halt the Cal PX's attempt to collect these payments under the charge-back mechanism, claiming the mechanism was not intended for these purposes, and even if it was so intended, such an application was unreasonable and destabilizing to the California power market. The FERC issued a ruling on these complaints eliminating the "charge-back" mechanism.
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"). The Company was among the sellers identified in this complaint and the Company filed its answer and motion to intervene. In its answer, the Company 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 the Company, to comply with additional reporting requirements with regard to certain wholesale power transactions. The Company has made required filings under the May 31 order. The Attorney General has filed a request for rehearing that is pending at the FERC. As addressed below, the California Attorney General has also threatened litigation against the Company 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 the Company of his intent to file a complaint in California state court against the Company 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. For each asserted violation, the letter indicates an intent to seek penalties of $2,500. The letter invited the Company to contact the California Attorney General's office before the complaint was filed, and the Company has met twice with the California Attorney General's office. Further discussions are contemplated. To date, suit 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 ("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 the Company. 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 to state court. The Company has joined with other cross-defendants in motions to dismiss the cross-claim. The Company cannot predict the outcome of this matter.
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. The Company trades with companies of various credit quality. 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, the Company 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.
In addition to sales directly to California, the Company sells power to customers in other jurisdictions who sell to California and whose ability to pay the Company may be dependent on payment from California. The Company is unable to determine whether 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 the Company, the Company may be exposed to credit risk, which did not exist prior to the California situation.
In 2001, in response to the increased credit risk and market price volatility described above, the Company provided an additional allowance against revenue of $3.8 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. The Company recorded additional reserves of $780,000 in the second quarter of 2002 as a result of the continuing credit degradation of many of its counterparties. Based on information available at June 30, 2002, the Company believes the total allowance for anticipated losses, currently established at $12.8 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, PNM and Western Resources announced that both companies' Boards of Directors approved an agreement under which PNM would acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing.
In July 2001, the KCC issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for a $151 million increase. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001, in New York state court. On May 10, 2002, the Company filed an Amended Complaint seeking unspecified damages from Western Resources for numerous breaches of contract related to the determination that the split-off required by the agreement was unlawful and required prior approval by the KCC. The Company also seeks unspecified damages for additional breaches of contract because: Western Resources failed to provide the Company with the opportunity to review and comment on information related to the transaction provided by Western Resources to third parties; Western Resources failed to obtain the Company's consent to amend existing employee compensation and benefits plans or create new ones; and Western Resources filed for approval of an alternative debt reduction plan that represents the abandonment of the split-off required by the agreement. In addition the Company seeks numerous declarations from the court, including that the Company was not obligated to perform because conditions regarding performance were not satisfied; the Company did not breach when it terminated the agreement; and the rate case order constitutes a material adverse effect under the terms of the agreement.
On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. However, the Company subsequently received a letter dated May 28, 2002, from counsel for Western Resources purporting to terminate the agreement and demanding payment of a $25 million termination fee, which the Company declined to pay.
On May 30, 2002, Western Resources filed counterclaims against the Company in New York state court alleging breach of contract and fraud. Western Resources alleged that the Company's January 7 letter constituted a withdrawal or adverse modification of the Company's adoption of the agreement or recommendation that its shareholders approve the agreement. As a result, Western Resources claims that the Company is liable for a $25 million termination fee plus costs and expenses (including attorneys fees) incurred in connection with the litigation. Western Resources also claims that the Company committed fraud by not timely disclosing to Western Resources its intentions not to proceed with the transaction and is seeking additional unspecified damages. The Company believes that the counterclaims filed by Western Resources are without merit and intends to vigorously defend itself against them. The Company also intends to vigorously pursue its own complaint.
On July 3, 2002, the Company filed a Motion for Partial Summary Judgment and for Dismissal of Counterclaims and Defenses.
The Company is currently unable to predict the outcome of its litigation with Western Resources.
Effects of Certain Events on Future Revenues
On October 1, 1999, Western Area Power Administration ("WAPA") filed a petition at the FERC requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA under the Company's Open Access Transmission Tariff on behalf of the United States Department of Energy ("DOE") as contracting agent for Kirtland Air Force Base ("KAFB").
In 2001, FERC issued a "proposed" order directing the Company to provide transmission service, but left the terms of service to be negotiated by the parties and subject to final FERC review and determination. In January 2002, the parties submitted a settlement agreement resolving most of the issues relating to the rates, terms and conditions of service. The settlement agreement reserves the Company's rights to seek rehearing and judicial review of any final order and to present other legal claims. On April 12, 2002, the FERC approved the settlement, and on April 29, 2002, the FERC issued its Final Order directing the Company to provide the service. 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. The Company requested rehearing of the April 29 final order. Thirty days passed without FERC action on the Company's request for rehearing, and the Company filed a petition for review in the United States Court of Appeals for the Tenth Circuit on July 19, 2002. A related PRC proceeding has been stayed, pending the outcome of the FERC case.
Should DOE on behalf of KAFB choose to use WAPA for purchase and transmission services instead of the current retail sale that the Company makes to DOE, the effect of the FERC's proposed order to provide transmission service, depends upon the Company's ability to sell the power to a different customer and the price that the Company would obtain if it makes such a sale. 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 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 the Company by the EPA, and the Company believes that all of the routine maintenance, repair, and replacement work undertaken at its power plants was and continues to be in accordance with the requirements of NSR and NSPS. However, by letter dated October 23, 2000, the New Mexico Environment Department ("NMED") made an information request of the Company, advising the Company that the NMED was in the process of assisting the EPA in the EPA's nationwide effort "of verifying that changes made at the country's utilities have not inadvertently triggered a modification under the Clean Air Act's Prevention of Significant Determination ("PSD") policies." The Company has responded to the NMED information request. In late June 2002, the Company received another information request from the NMED for a list of capital budget item projects budgeted or completed in 2001 or 2002. The Company has responded to this NMED information request.
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 the Company of GCT's intent to file a so-called "citizen suit" under the Clean Air Act, alleging that the Company and co-owners of the SJGS violated the Clean Air Act, and the implementing federal and state regulations, at SJGS. Pursuant to that notification, on May 16, 2002, the GCT filed suit in federal district court in New Mexico against the Company (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 all four units. 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. The Company filed its answer in federal court on June 6, 2002, denying the material allegations in the complaint. The parties are presently addressing with the federal magistrate a discovery schedule. Based on its investigation to date, the Company firmly believes that the allegations are without merit and vigorously disputes the allegations. The Company has always 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 Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. The Company's investigation indicates that the leak was an isolated incident likely caused by a combination of corrosion and increased pressure. The Company also is cooperating with an investigation of the incident by the PRC's Pipeline Safety Bureau, which issued its report on March 18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the Company by the injured persons along with several claims for property and business interruption damages have been resolved. There can be no assurance that the outcome of this matter will not have a material impact on the results of operations and financial position of the Company.
NAVAJO NATION TAX ISSUES
Arizona Public Service Company ("APS"), the operating agent for Four Corners, has informed the Company that in March 1999, APS initiated discussions with the Navajo Nation regarding various tax issues in conjunction with the expiration of a tax waiver, in July 2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to the possessory interest tax and the business
activity tax associated with the Four Corners operations on the reservation. The Company believes that the resolution of these tax issues will require an extended process and could potentially affect the cost of conducting business activities on the reservation. The Company is unable to predict the ultimate outcome of discussions with the Navajo Nation regarding these tax issues and cannot estimate with any certainty the potential impact on the Company's operations.
LANDOWNER ENVIRONMENTAL CLAIMS
In March 2002, a lawsuit was filed, by a landowner owning property in the vicinity of SJGS, against the Company and the owner of the coal mine that supplies coal to the plant. 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. The Company 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 the Company that apparent disturbances to archeological sites had been discovered in and around the rights-of-way for the Company's transmission lines in the Carson National Forest in New Mexico. Great Southwestern performed "climb and tighten" activities on those transmission lines. The Company 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. The Company has given the Corps of Engineers notice concerning the disturbances in arroyos. The Corps of Engineers has acknowledged the Company's notice and asked the Company 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 the Company to undertake an assessment and possible related mitigation measures with respect to the archeological sites in question. The Company has contracted for an archeological assessment and a proposed remediation plan with respect to the disturbances. The Company has provided Great Southwestern with notice and a demand for indemnity. 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.
NEW AND PROPOSED ACCOUNTING STANDARDS
Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143. The statement requires the recognition of a liability for legal obligations associated with the retirement of a tangible long-lived asset that result from the acquisition, construction or development or the normal operation of a long-lived asset. The asset retirement
obligation is required to be recognized at its fair value when incurred. The cost of the asset retirement obligation is required to be capitalized by increasing the carrying amount of the related long-lived asset by the same amount as the liability. This cost must be expensed using a systematic and rational method over the related asset's useful life. SFAS 143 is effective for the Company beginning January 1, 2003. The Company is currently assessing the impact of SFAS 143 and is unable to predict its impact on the Company's operating results and financial position at this time.
Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the FASB issued SFAS 144. The statement retains the requirements of the previously issued pronouncement on asset impairment, Statement of Financial Accounting Standards No. 121 ("SFAS 121"); however the SFAS 144 removes goodwill from the scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a "primary asset" approach for a group of assets and liabilities that represents the unit of accounting to be evaluated for impairment. In addition, SFAS 144 changes the measurement of long-lived assets to be disposed of by sale, as accounted for by Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued operations are no longer measured on a net realizable value basis, and their future operating losses are no longer recognized before they occur. The Company does not believe SFAS 144 will have a material effect on its future operating results or financial position.
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. According to the old policy, 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 02-03 "Recognition and Reporting of Gains and Losses" on Energy Trading Contracts under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." This EITF issue addresses various aspects of the accounting for contracts involved in energy trading and risk management activities. The EITF concluded that all mark-to-market gains and losses on energy trading contracts should be shown net in the income statement whether or not settled physically. The EITF did not reach a consensus and continues to debate whether the recognition of unrealized gains and losses at inception of an energy trading contract is appropriate in the absence of quoted market prices or current market transactions for contracts with similar terms. The EITF also expanded the disclosure requirements for energy trading activities. Implementation of the consensus for recording energy trading activities net is effective for the Company beginning with its 2002 third quarter financial statements. Comparative financial statements for prior periods are required to be reclassified to conform to the EITF's consensus. The Company is currently assessing the impact of implementing EITF Issue No. 02-03 and is unable to predict its effect on the Company's presentation of operating results. 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.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
Statements made in this filing that relate to future events are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that all forward-looking statements are based upon current expectations and are subject to risk and uncertainties. The Company assumes no obligation to update this information.
Because actual results may differ materially from expectations, the Company cautions readers not to place undue reliance on these statements. A number of factors, including weather, fuel costs, changes in the local and national economy, changes in supply and demand in the market for electric power, the outcome of litigation relating to the Company's terminated transaction with Western Resources, the performance of generating units and transmission system, the 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, 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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices, changes in interest rates and, historically, adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. Information about the Company's financial instruments is set forth in the Financial Instruments note in the Notes to Consolidated Financial Statements and incorporated by reference. The following additional information is provided.
Risk Management
The Company controls the scope of its various forms of risk through a comprehensive set of policies and procedures and oversight by senior level management and the Board of Directors. The 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.
Commodity Risk
Trading and marketing operations often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. These risks fall into three different categories: price and volume volatility, credit risk of trading counterparties and adequacy of the control environment for trading. The Company routinely enters into forward contracts and options to hedge purchase and sale commitments, fuel requirements and to minimize the risk of market fluctuations on the Generation and Trading Operations.
The Company's wholesale power marketing operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its retail load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases.
The Company assesses the risk of these derivatives using the VAR method, in order to maintain the Company's total exposure within management-prescribed limits. The Company utilizes the variance/covariance model of VAR, which is a probabilistic model that measures the risk of loss to earnings in market sensitive instruments. The variance/covariance model relies on statistical relationships to analyze how changes in different markets can affect a portfolio of instruments with different characteristics and market exposure. VAR models are relatively sophisticated; however, the quantitative risk information is limited by the parameters established in creating the model. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used. The VAR methodology employs the following critical parameters: volatility estimates, market values of open positions, appropriate market-oriented holding periods and seasonally adjusted correlation estimates. The Company uses a holding period of three days as the estimate of the length of time that will be needed to liquidate the positions. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. The confidence level established is 99%. For example, if VAR is calculated at $10 million, it is estimated at a 99% confidence level that if prices move against the Company's positions, the Company's pre-tax gain or loss in liquidating the portfolio would not exceed $10 million in the three days that it would take to liquidate the portfolio.
The Company accounts for the sale of 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 the Company's trading portfolio, the VAR was $0.8 million at June 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 $5.0 million at June 30, 2002.
The Company's VAR is regularly monitored by the Company's RMC. The RMC has put in place procedures to ensure that increases in VAR are reviewed and, if deemed necessary, acted upon to reduce exposures. The VAR represents an estimate of the potential gains or losses that could be recognized on the Company's wholesale power marketing portfolio given current volatility in the market, and is not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market rates, operating exposures, and the timing thereof, as well as changes to the Company's wholesale power marketing portfolio during the year.
In addition, the Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to 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. The Company's credit risk with its largest counterparty as of June 30, 2002 was $4.5 million.
The Company 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 Company's purchased gas adjustment clause as deemed prudently incurred by the PRC. As a result, earnings are not affected by gains and losses generated by these instruments.
Interest Rate Risk
As of June 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 June 30, 2002, the fair value of these instruments would decline by 69.5% or $0.7 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.
The Company has long-term debt which subjects it to the risk of loss associated with movements in market interest rates. All of the Company's long-term debt is fixed-rate debt, and therefore, does not expose the Company's earnings to a risk of loss due to adverse changes in market interest rates. However, the fair value of these debts instruments would increase by approximately 4.2% or $40.4 million if interest rates were to decline by 50 basis points from their levels at June 30, 2002. As of June 30, 2002, the fair value of the Company's long-term debt was $962 million as compared to a book-value of $954 million. In general, an increase in fair value would impact earnings and cash flows if the Company were to re-acquire all or a portion of its debt instruments in the open market prior to their maturity. Certain issuances of the Company's debt have call dates in December 2002 and August 2003. To hedge against the risk of rising interest rates and their impact on the economies of calling the debt, the Company has entered into two forward starting swaps in 2001 and three additional contracts in 2002. These forward interest rate swaps effectively lock-in interest rates for the notional amount of the debt that is callable at a rate of approximately 4.9% plus an adjustment for the Company's and industry's credit rating. At June 30, 2002, the fair market value of these derivative financial instruments was approximately $3.0 million in the Company's favor.
The Company contributed $6.1 million in 2001 to a trust established to fund decommissioning costs for PVNGS. In January 2002, the Company contributed $23.5 million for plan year 2001 to the trust for the Company's pension plan, and other post retirement benefits. The securities held by the trusts had an estimated fair value of $473.7 million as of June 30, 2002, of which approximately 29% 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 June 30, 2002, the decrease in the fair value of the securities would be 3.1% or $4.3 million. The Company does not currently recover or return in jurisdictional rates losses or gains on these securities; therefore, the Company is at risk for shortfalls in its funding of its obligations due to investment losses. However, the Company does not believe that long-term market returns over the period of funding will be less than required for the Company to meet its obligations.
Equity Market Risk
As discussed above under Interest Rate Risk, the Company contributes to trusts established to fund its share of the decommissioning costs of PVNGS and other post retirement benefits. The trust holds certain equity securities as of June 30, 2002. These equity securities also expose the Company to losses in fair value. Approximately 54% of the securities held by the various trusts were equity securities as of June 30, 2002. Similar to the debt securities held for funding decommissioning and certain pension and other postretirement costs, the Company does not recover or return in jurisdictional rates losses or gains on these equity securities.
In 2001, the Company implemented an enhanced cash management strategy using derivative instruments based on the Standard & Poors 100 and 500 indices. The strategy is designed to capitalize on high market volatility or benefit from market direction. An investment manager is utilized to execute the program. The program is carefully managed by the RMC and limited to a one-day VAR of $5 million and a loss limit of $7.5 million. Trades are closed-out before the end of a reporting period and typically within the same day of execution. Recently, the RMC recommended and the Finance Committee approved the use of derivatives based on the Nasdaq composite index.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The following represents a discussion of legal proceedings that first
became a reportable event in the current year or material developments for those
legal proceedings previously reported in the Company's 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 the Company owns a 13% ownership interest in Units 4 and 5 of Four Corners.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the Navajo Nation Pesticide Act (collectively, the "Navajo Acts"). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those that occur at Four Corners. The Four Corners participants dispute that purported authority, and by letter dated October 12, 1995, the Four Corners participants requested the United States Secretary of the Interior to resolve their dispute with the Navajo Nation regarding whether or not the Navajo Acts apply to operations of Four Corners. On October 17, 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, seeking, among other things, a declaratory judgment that:
o the lease and federal easement preclude the application of the Navajo Acts to the operations of Four Corners; and
o the Navajo Nation and its agencies and courts lack adjudicatory jurisdiction to determine the enforceability of the Navajo Acts as applied to Four Corners.
On October 18, 1995, the Navajo Nation and the Four Corners participants agreed to indefinitely stay these proceedings so that the parties may attempt to resolve the dispute without litigation. The Secretary and the Court have stayed these proceedings pursuant to a request by the parties. The Company cannot currently predict the outcome of this matter.
In February 1998, the EPA issued regulations identifying those Clean Air Act provisions for which it is appropriate to treat Indian tribes in the same manner as states. The EPA has announced that it has not yet determined whether the Clean Air Act would supersede pre-existing binding agreements between the Navajo Nation and the Four Corners participants that could limit the Navajo Nation's environmental regulatory authority over Four Corners. The Company believes that the Clean Air Act does not supersede these pre-existing agreements. The Company cannot currently predict the outcome of this matter.
On August 8, 2000, the EPA signed an Eligibility Determination for the Navajo Nation for Grants Under Section 105 of the Clean Air Act in which the EPA determined that the Navajo Nation was eligible to receive grants under the Clean Air Act. On September 8, 2001, after learning of the eligibility determination, APS, as Four Corners operating agent, filed a Petition for Review of the EPA's decision in the United States Court of Appeals for the Ninth Circuit in order to ensure that the EPA's August 2000 determination not be construed to constitute a determination of the Navajo Nation's authority to regulate Four Corners. APS, 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, the Company was informed that the DOE had entered into an agency agreement with WAPA on behalf of KAFB, one of the Company's largest retail electric customers, by which WAPA would competitively procure power for KAFB. The proposed wholesale power procurement was to begin at the expiration of KAFB's power service contract with the Company in December 1999. On May 4, 1999, the Company received a request for network transmission service from WAPA pursuant to Section 211 of the Federal Power Act to facilitate the delivery of wholesale power to KAFB over the Company's transmission system. The Company denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB is and will continue to be a retail customer until the date that KAFB can elect customer choice service under the provisions of the Restructuring Act of 1999. The Company also cited several provisions of federal law that prohibit the provision of such service to WAPA. On October 1, 1999, WAPA filed a petition requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA on behalf of DOE and several other entities
located on KAFB under the Company's Open Access Transmission Tariff. The petition claimed KAFB is a wholesale customer of the Company, not a retail customer. By order entered on April 13, 2001 the FERC denied the WAPA transmission application. The FERC order determined, among other things, that WAPA had failed to demonstrate that its sales to DOE are sales for resale and also that WAPA failed to qualify for certain claimed exemptions under the Federal Power Act that would have entitled it to provide expanded service to DOE. WAPA requested rehearing of FERC's April 13, 2001 order.
In a proposed order issued on June 13, 2001, FERC granted WAPA's request for rehearing. FERC determined that WAPA qualified for an exemption to the prohibition against an order requiring service to retail customers and that FERC therefore could require the Company to provide the requested service. FERC directed the Company and WAPA to engage in negotiations concerning rates, terms and conditions of service, including compensation. On January 18, 2002, the parties submitted a settlement agreement resolving most of the issues relating to the rates, terms and conditions of service. The partial settlement reserved one issue for FERC decision or further proceedings. The reserved issue relates to whether WAPA is entitled to a credit against payments for transmission service for certain facilities located near KAFB. The settlement agreement filed at FERC reserves the Company's rights to seek rehearing and judicial review of any final order and to present other legal claims. On April 12, 2002, the FERC approved the settlement. On April 29, 2002, the FERC issued its final order directing the Company to provide service. WAPA requested rehearing of the April 12 order approving the settlement, and FERC issued an order granting rehearing for further consideration. The Company requested rehearing of the April 29 final order directing the Company to provide service. Thirty days passed without FERC action on the Company's request for rehearing and it is deemed denied. The Company filed a petition for review of the final order and the denial of its request for rehearing in the United States Court of Appeals for the Tenth Circuit on July 19, 2002.
In a separate but related proceeding, the Company and the United States Executive Agencies on behalf of KAFB are involved in a PRC case regarding a dispute over the specific Company tariff language under which the Company provides retail service to KAFB. The Company agreed to continue to provide service to KAFB after expiration of the contract and KAFB continues to purchase retail service pending resolution of all relevant issues. The PRC case has been held in abeyance, pending the outcome of the FERC proceeding.
AVISTAR SEVERANCE
When the Company sold its water utility assets to the City of Santa Fe ("City") in 1995, the parties also entered into a Maintenance and Operations Agreement ("Agreement"), agreeing that the City would offer employment to the water utility employees when the Agreement expired. The Agreement was assigned to Avistar, Inc., and it expired in July 2001. The City assumed all maintenance and operations, and offered employment to the employees.
Because the employees would continue performing the same jobs at the same location(s), the Company had previously excluded the non-union employees from eligibility for severance benefits under the Company's non-union severance plans. Similarly, the IBEW Local 611 had been on notice that the Company had negotiated for the continued employment of the IBEW-represented employees, making them ineligible for severance benefits under Article 24 of the Collective Bargaining Agreement ("CBA") between the Company and the IBEW.
In July 2001, the Agreement ended, and most of the water operations employees accepted employment with the City. However, on March 27, 2001, the IBEW 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.
WESTERN RESOURCES
On November 9, 2000, the Company and Western Resources announced that both companies' Boards of Directors approved an agreement under which the Company would acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing.
In July 2001, the KCC issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for $151 million increase. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001, in New York state court. On May 10, 2002, the Company filed an Amended Complaint seeking unspecified damages from Western Resources for numerous breaches of contract related to the determination that the split-off required by the agreement was unlawful and required prior approval by the KCC. The Company also seeks unspecified damages for additional breaches of contract because: Western Resources failed to provide the Company with the opportunity to review and comment on information related to the transaction provided by Western Resources to third parties; Western Resources failed to obtain the Company's consent to amend existing employee compensation and benefits plans or create new ones; and Western Resources filed for approval of an alternative debt reduction plan that represents the abandonment of the split-off required by the agreement. In addition the Company seeks numerous declarations from the court, including that the Company was not obligated to perform because conditions regarding performance were not satisfied; the Company did not breach when it terminated the agreement; and the rate case order constitutes a material adverse effect under the terms of the agreement.
On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. However, the Company subsequently received a letter dated May 28, 2002, from counsel for Western Resources purporting to terminate the agreement and demanding payment of a $25 million termination fee, which the Company declined to pay.
On May 30, 2002, Western Resources filed counterclaims against the Company in New York state court alleging breach of contract and fraud. Western Resources alleged that the Company's January 7 letter constituted a withdrawal or adverse modification of the Company's adoption of the agreement or recommendation that its shareholders approve the agreement. As a result Western Resources claims that the Company is liable for a $25 million termination fee plus costs and expenses (including attorneys fees) incurred in connection with the litigation. Western Resources also claims that the Company committed fraud by not timely disclosing to Western Resources its intentions not to proceed with the transaction and is seeking additional unspecified damages. The Company believes that the counterclaims filed by Western Resources are without merit and intends to vigorously defend itself against them. The Company also intends to vigorously pursue its own complaint.
On July 3, 2002, the Company filed a Motion for Partial Summary Judgment and for Dismissal of Counterclaims and Defenses.
The Company is unable to predict the ultimate outcome of its litigation with Western Resources.
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"). The Company was among the sellers identified in this complaint and the Company filed its answer and motion to intervene. In its answer, the Company 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 the Company, to comply with additional reporting requirements with regard to certain wholesale power transactions. The Company has made required filings under the May 31 order. The Attorney General has filed a request for rehearing that is pending at the FERC.
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 ("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 the Company. 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 to state court. The Company 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 Grand Canyon Trust and Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a so-called "citizen suit" under the Clean Air Act, alleging that the Company and co-owners of the SJGS violated the Clean Air Act, and the implementing federal and state regulations, at SJGS. Pursuant to that notification, on May 16, 2002, the GCT filed suit in federal district court in New Mexico against the Company (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 all four units. 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. The Company filed its answer in federal court on June 6, 2002, denying the material allegations in the complaint. The parties are presently addressing with the federal magistrate a discovery schedule. Based on its investigation to date, the Company firmly believes that the allegations are without merit and vigorously disputes the allegations. The Company has always 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 the Company and the owner of the coal mine that supplies coal to the plant. 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. The Company is vigorously defending this matter, but is unable to predict the outcome of this matter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Annual Meeting
The annual meeting of shareholders was held on May 14, 2002. The matters voted on at the meeting and the results were as follows:
The election of the following nominees to serve as directors as follows:
Votes
Against
Director Votes For Or Withheld
-------- --------- -----------
Term expiring in 2003:
Paul F. Roth 33,847,332 177,248
Terms expiring in 2005:
R. Martin Chavez, Ph.D. 33,548,810 475,770
Joyce A. Godwin 33,856,387 168,193
Manuel T. Pacheco, Ph.D. 33,556,254 468,326
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As reported in the Definitive 14A Proxy Statement filed April 10, 2002, the name of each other director whose term of office as director continues after the meeting is as follows:
Robert G. Armstrong
Benjamin F. Montoya
Theodore F. Patlovich
Robert M. Price
Jeffry E. Sterba
Subsequent to the annual meeting, Benjamin F. Montoya resigned from the Board.
On April 19, 2002, the Company announced that it would remove Proposal 2:
Approval of Independent Public Accountants from the agenda for the annual
meeting. Due to the developments regarding Arthur Andersen, LLP ("Andersen"),
the Company's proposed auditor, it was considered likely that the Board of
Directors of PNM Resources, Inc. would replace Andersen during 2002. On June 7,
2002, the Board of Directors dismissed Andersen and selected Deloitte and
Touche, LLP to serve as independent accountants for 2002.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
15.0 Letter Re: Unaudited Interim Financial Information
3.1.1 Restated Articles of Incorporation of PNM, as amended
through May 31, 2002.
3.2.1 Bylaws of PNM with all Amendments to and including
May 31, 2002.
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.
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b. Reports on Form 8-K:
Report dated and filed May 23, 2002 reporting the Company Responds to FERC Inquiry: No Inappropriate Trades.
Report dated and filed June 10, 2002 reporting the Company's Dismissal of Arthur Andersen, LLP as Independent Public Accountants for PNM Resources and its affiliates.
Report dated and filed June 10, 2002 reporting the Company's Comparative Operating Statistics for the month of May 2002 and 2001 and the year ended May 30, 2002 and 2001.
Report dated and filed June 18, 2002 reporting the Company's Letters from Arthur Andersen, LLP to the Securities and Exchange Commission dated June 11, 2002 regarding PNM Resources, Inc. and Public Service Company of New Mexico.
Report dated and filed July 10, 2002 reporting the Company Lowers its 2002 Earnings Estimate.
Report dated and filed July 12, 2002 reporting the Company's Comparative Operating Statistics for the month of June 2002 and 2001 and the year ended June 30, 2002 and 2001.
Report dated and filed July 17, 2002 reporting the Company Declares Common Stock Dividend.
Report dated and filed July 18, 2002 reporting the Company Names Two New Directors.
Report dated and filed July 23, 2002 reporting the Company's Quarter Ended June 30, 2002 Earnings Announcement; Consolidated Statement of Earnings, Consolidated Balance Sheets, Consolidated Statement of Cash Flows and Comparative Operating Statistics.
Report dated and filed July 24, 2002 reporting the Company's Announcement to Employees a Reorganization of its Management Committee.
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.
Date: August 14, 2002 /s/ John R. Loyack
---------------------------------------------
John R. Loyack
Vice President
and Chief Accounting Officer
(Officer duly authorized to sign this report)
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EXHIBIT 15.0
INDEPENDENT ACCOUNTANTS' AWARENESS LETTER
PNM Resources, Inc.
Albuquerque, New Mexico
We have made a review, in accordance with standards established by the American Institute of Certified Public Accountants, of the unaudited interim financial information of PNM Resources, Inc and subsidiaries for the three and six-month periods ended June 30, 2002, as indicated in our report dated August 2, 2002; because we did not perform an audit, we expressed no opinion on that information.
We are aware that our report referred to above, which is included in your quarterly report on Form 10-Q for the quarter ended June 30, 2002, is incorporated by reference in Registration Statement File No. 33-65418, Registration Statement File No. 333-03289, Registration Statement File No. 333-03303, Registration Statement File No. 333-10993, Registration Statement File No. 333-32170, Registration Statement File No. 333-53367, Registration Statement File No. 333-61598, Registration Statement No. 333-73648, Registration Statement No. 333-76288, and Registration Statement No. 333-76316.
We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.
/s/ Deloitte & Touche LLP August 14, 2002 Omaha, Nebraska |
EXHIBIT 15.1
INDEPENDENT ACCOUNTANTS' AWARENESS LETTER
PNM Resources, Inc.
Albuquerque, New Mexico
We have made a review, in accordance with standards established by the American Institute of Certified Public Accountants, of the unaudited interim financial information of PNM Resources, Inc and subsidiaries for the three and six-month periods ended June 30, 2002, as indicated in our report dated August 2, 2002; because we did not perform an audit, we expressed no opinion on that information.
We are aware that our report referred to above, which is included in your quarterly report on Form 10-Q for the quarter ended June 30, 2002, is incorporated by reference in Registration Statement File No. 333-03289, Registration Statement File No. 333-03303, Registration Statement File No. 333-10993, Registration Statement File No. 333-32170, Registration Statement File No. 333-61598, Registration Statement No. 333-73648, Registration Statement No. 333-76288, and Registration Statement No. 333-76316.
We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.
/s/ Deloitte & Touche LLP August 14, 2002 Omaha, Nebraska |
Exhibit 3.1.1
[SEAL]
OFFICE OF THE
PUBLIC REGULATION COMMISSION
RESTATED CERTIFICATE OF INCORPORATION
OF
PUBLIC SERVICE COMPANY OF NEW MEXICO
3243953
The Public Regulation Commission certifies that duplicate originals of Restated Articles of Incorporation attached hereto, duly signed and verified pursuant to the provisions of the
BUSINESS CORPORATION ACT
(53-11-1 to 53-18-12 NMSA 1978)
have been received by it and are found to conform to law.
Accordingly, by virtue of the authority vested in it by law, the Public Regulation Commission issues this Restated Certificate of Incorporation and attached hereto a duplicate original of the Restated Articles of Incorporation.
Dated: MAY 31, 2002
In testimony whereof, the Public Regulation Commission of the State of New Mexico has caused this certificate to be signed by its Chairman and the seal of said Commission to affixed at the City of Santa Fe.
/s/
----------------------------------
Chairman
/s/
----------------------------------
Bureau Chief
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ARTICLES OF AMENDMENT TO
THE RESTATED ARTICLES OF INCORPORATION
OF
PUBLIC SERVICE COMPANY OF NEW MEXICO
Pursuant to the provisions of NMSA 1978, Section 53-13-4 (2001), Public Service Company of New Mexico adopts the following Articles of Amendment to its Restated Articles of Incorporation, as amended:
I. ARTICLES FIRST through EIGHTH of the Restated Articles of Incorporation, as previously amended, are amended as follows, and ARTICLES NINTH through FOURTEENTH are deleted:
A. ARTICLE FIRST is amended to read: "ARTICLE I
B. ARTICLE SECOND is amended to read: "ARTICLE II
D. ARTICLE FOURTH is amended to read: "ARTICLE IV
A. Authorized Capital Shares. The total number of shares of stock which the Corporation shall have the authority to issue is Forty (40) Million shares of Common Stock, no par value, and Ten (10) Million shares of Preferred Stock, no par value, and shall be issued for such minimum consideration as authorized by the Board of Directors.
B. Common Stock. The Board of Directors is authorized by resolution to provide from time to time for the issuance of shares of Common Stock to existing holders of Common Stock subject to the following restrictions and qualifications:
(1) Dividends. Subject to any rights of holders of Preferred Stock, dividends (payable in cash, stock or otherwise) as may be determined by the Board of Directors in accordance with dividend policy established by the shareholders may be declared and paid on the Common Stock from time to time from any available funds, property or shares.
(2) Voting Rights. Subject to any rights of holders of Preferred Stock to vote on a matter as a class or series, each outstanding share of Common Stock shall be entitled to one vote on each matter submitted to a vote of holders of Common Stock at a meeting of shareholders. Cumulative voting for the election of directors of the Corporation shall not be permitted.
(3) Liquidation, Dissolution or Winding Up. In the event of any liquidation, dissolution or winding up of the Corporation, the holders of Common Stock shall be entitled to receive the net balance of any assets of the Corporation remaining after any distribution of the assets of the Corporation to the holders of Preferred Stock to the extent necessary to satisfy any preferences to the assets and satisfaction of all debt of the Corporation.
(4) Other Preferred Stock Rights. The issuance of shares of Common Stock to existing holders of Common Stock shall be subject to the rights of holders of outstanding Preferred Stock as provided in Article VIII.
C. Preferred Stock. The Board of Directors is authorized by resolution to provide from time to time for the issuance of shares of Preferred Stock in series and to fix, from time to time before issuance, the designation, preferences, privileges and voting powers of the shares of each series of Preferred Stock and its restrictions or qualifications, limited to the following:
(1) the serial designation, authorized number of shares and the stated value;
(2) the dividend rate, if any, the date or dates on which the dividends will be payable, and the extent to which the dividends may be cumulative;
(3) the price or prices at which shares may be redeemed, and any terms, conditions and limitations upon any redemption;
(4) the amount or amounts to be received by the holders in the event of dissolution, liquidation, or winding up of the Corporation;
(5) any sinking fund provisions for redemption or purchase of shares of any series;
(6) the terms and conditions, if any, on which shares may be converted into, or exchanged for, shares of other series of Preferred Stock, of the Corporation, but may not be converted into, or exchanged for, shares of Common Stock of the Corporation; and
(7) the voting rights, if any, for the shares of each series, limited to circumstances when:
(a) the Corporation fails to pay dividends on the applicable series; and
(b) when a proposed amendment to these Articles would have an adverse impact on the rights and privileges of the preferred stockholders.
D. Preemptive Rights. The holders of Preferred Stock shall not have a preemptive right to acquire authorized but unissued shares, securities convertible into shares or carrying a right to subscribe to or acquire shares, except under such terms and conditions as may be provided by the Board of Directors."
E. ARTICLE FIFTH is amended to read: "ARTICLE V
The number of directors of the Corporation shall be as specified in the Bylaws but shall be no less than three (3) and no more than twelve (12). Directors shall be elected annually at the annual meeting of shareholders."
F. ARTICLE SIXTH is amended to read: "ARTICLE VI
The liability of the directors of the Corporation for monetary damages shall be eliminated or limited to the fullest extent permissible under New Mexico law as it may be amended from time to time."
G. ARTICLE SEVENTH is amended to read: "ARTICLE VII
B. The Board of Directors is not authorized to alter, amend or repeal the provisions of the Corporation's Bylaws relating to the number of Directors, compensation of Directors, selection of the Chairman of the Board of Directors, and selection of the President.
C. The Bylaws of the Corporation shall:
(1) provide for the shareholders to fix the number of directors;
(2) require that Board compensation be established by the shareholders;
(3) require that the Chairman of the Board be selected by the shareholders; and
(4) require that the President of the Corporation be selected by the shareholders."
H. ARTICLE EIGHTH is amended to read: "ARTICLE VIII
1965 SERIES PREFERRED STOCK
A. The only series of Preferred Stock that is outstanding as of the effectiveness of these Restated Articles of Incorporation is the Cumulative Preferred Stock, 1965 Series, 4.58% (the "1965 Series Preferred Stock"). The rights and privileges accorded to holders of the 1965 Series Preferred Stock
shall not be diminished as a result of adoption of these Restated Articles of Incorporation. The specific terms of the 1965 Series Preferred Stock are set forth in the "Certificate Setting Forth Resolutions of Board of Directors Creating a Series of Cumulative Preferred Stock and Fixing the Amount, Designation, Characteristics and Terms Thereof", dated January 21, 1965 (the "1965 Series Resolutions"). The general rights and privileges of the 1965 Series Preferred Stock are set forth in this Article, which shall be applicable only to the 1965 Series Preferred Stock. The 1965 Series Preferred Stock is senior to the Common Stock and the Common Stock is subject to all the rights and preferences of the 1965 Series Preferred Stock.
B. The 1965 Series Preferred Stock has the preferences and voting powers or restrictions, or qualifications as set forth in this Article. In addition, the 1965 Series Preferred Stock has the designations, terms and characteristics set forth in the 1965 Series Resolutions.
C. The holders of the 1965 Series Preferred Stock, in preference to the holders of any stock ranking junior to the 1965 Series Preferred Stock, shall be entitled to receive cash dividends at the rate per annum specified in the 1965 Series Resolutions, and no more, payable on dates fixed by the Board of Directors at the time of creation of the series, when and as declared by the Board of Directors, out of any funds of the Corporation legally available for that purpose. The dividends shall be cumulative from the first day of the dividend period in which the stock shall have been originally issued and shall be paid, or declared and set apart for payment, before any dividends shall be declared or paid on or set apart for any class of stock ranking junior to the 1965 Series Preferred Stock as to dividends or assets, so that if, for any past dividend period, dividends or the current dividend period dividends on the 1965 Series Preferred Stock shall not have been paid, or declared and set apart for payment, the deficiency shall be fully paid or declared and funds set apart for the payment of those dividends before any dividends shall be declared or paid on
or set apart for any class of stock ranking junior to the 1965 Series Preferred Stock as to dividends or assets. No dividends shall at any time be paid on or set apart for any share of 1965 Series Preferred Stock unless at the same time there shall be paid on or set apart for all shares of 1965 Series Preferred Stock then outstanding dividends in such amount that the holders of all shares of 1965 Series Preferred Stock shall receive or have set apart for them a uniform percentage of the full annual dividend to which they are, respectively, entitled. The term "dividend period," as used herein, refers to each period of three consecutive calendar months ending on the day next preceding each date on which dividends, if declared, shall be payable. Unless and until full cumulative dividends upon the 1965 Series Preferred Stock for all past dividend periods and for the current dividend period shall have been paid, or declared and set apart for payment, no dividend whatsoever (other than a dividend payable in shares of any class of stock ranking junior to the 1965 Series Preferred Stock as to dividends and assets) shall be paid or declared on, and no distribution shall be made or ordered in respect of, any class of stock ranking junior to the 1965 Series Preferred Stock as to dividends or assets, and no money (other than the net proceeds received from the sale of stock ranking junior to the 1965 Series Preferred Stock as to dividends or assets) shall be set aside or applied to the purchase or redemption (through a sinking fund or otherwise) of any class of stock ranking junior to the 1965 Series Preferred Stock as to dividends or assets.
D. In the event of the liquidation, dissolution or winding up, whether voluntary or involuntary, of the Corporation, the holders of shares of 1965 Series Preferred Stock shall be entitled, in preference to any class of stock ranking junior to the 1965 Series Preferred Stock as to dividends or assets, to be paid in full, out of the net assets of the Corporation, the liquidation price of their shares plus an amount equal to the accrued dividends on their shares to the date of distribution. In the event the liquidation, dissolution or winding up of the Corporation is voluntary, the holders of the 1965 Series Preferred Stock shall also be entitled to receive for each share, in preference to any class of stock ranking junior to the 1965 Series Preferred Stock as to dividends or assets, such premium or premiums as may be fixed by the Board of Directors at the time of creation of the series. Unless and until payment in full is made to the holders of shares of the 1965 Series Preferred Stock, no distribution shall be made to any class of stock ranking junior to the 1965 Series Preferred Stock as to dividends or assets. If upon any liquidation, dissolution or winding up, the assets distributable among the holders of the 1965 Series Preferred Stock are insufficient to permit the payment of the full preferential amounts to which they are entitled, then the entire assets of the Corporation to be distributed shall be distributed among the holders of the 1965 Series Preferred Stock ratably in proportion to the full preferential amounts to which they are respectively entitled. A statutory consolidation or merger of the Corporation shall not be deemed to be a liquidation, dissolution or winding up of the Corporation within the meaning of this section.
E.(1) The Board of Directors of the Corporation shall have the right at any time, subject to any initial limiting period set forth in the 1965 Series Resolutions, and from time to time to redeem all or any part of the 1965 Series Preferred Stock by paying to the holders of the shares to be redeemed the redemption price or prices of the shares, which shall include, in each case, an amount equal to the accrued dividends on the shares to the date fixed for redemption. In the case of the redemption of shares, the redemption price or prices shall be the redemption price or prices as fixed by the Board of Directors at the time of creation of the series plus an amount equal to the accrued dividends to the date fixed for redemption. Not less than thirty (30) nor more than sixty (60) days prior to the date fixed for redemption of any shares of the 1965 Series Preferred Stock, notice of the intention of the Corporation to redeem the shares, specifying the date and place of redemption, shall be deposited in a United States post office or mail box at any place in the United States addressed to each holder of record of the shares to be redeemed at his or her address as it appears upon the records of the Corporation and the time of the mailing shall be deemed to be the time of the giving of notice.
(2) In every case of redemption of less than all of the outstanding shares of the 1965 Series Preferred Stock, at the option of the Board of Directors, the redemption shall be made pro rata or the shares of the series to be redeemed shall be chosen by lot in the manner prescribed by resolution of the Board of Directors; provided, however, that the selection shall be made as set forth in this subsection, in respect of any registered holder of the 1965 Series Preferred Stock having one thousand (1,000) shares or more of the 1965 Series Preferred Stock registered in his or her name. If, at the time any selection by lot is to be made, one thousand (1,000) shares or more of the aggregate number of shares of the 1965 Series Preferred Stock are registered in the name of one holder, then before making the selection by lot, the Corporation shall allocate
to each registered holder holding one thousand (1,000) shares or more of the series a proportion of the shares to be redeemed equal, as nearly as practicable, to the proportion that the shares of the series then outstanding registered in the name of the holder bears to all shares of the series then outstanding. In that case, the selection by lot of the number of shares to be redeemed not so allocated shall be made from the registered holders holding less than one thousand (1,000) shares of the series.
(3) The Corporation may deposit in trust with a bank or trust company the aggregate redemption price of the shares to be redeemed, for payment on or before the redemption date to the holders of the shares, upon surrender of the certificates for the shares. The bank or trust company shall be named in the notice of redemption, shall be located in the City of New York, New York, and shall have capital, surplus and undivided profits aggregating at least $2,000,000. The deposit in trust may, at the option of the Corporation, contain terms so that, if the holder of any shares of 1965 Series Preferred Stock called for redemption does not claim the amount on deposit for the payment of the redemption price within six years after the date fixed for redemption, the bank or trust company shall on demand pay the amount to the Corporation or its successor. The bank or trust company shall thereafter be released from any and all further liability with respect to the payment of the redemption price and the holder of the shares shall be entitled to look only to the Corporation or its successor for payment. Upon the giving of notice of redemption and upon the deposit of the redemption price, or if no deposit is made, upon the redemption date (unless the Corporation defaults in making payment of the redemption price as set forth in the notice), the holders shall cease to be stockholders with respect to the shares, and from and after the making of the deposit and the giving of the notice, or, if no deposit is made, after the redemption date (the
Corporation not having defaulted in making payment of the redemption price as set forth in the notice), the shares shall no longer be transferable on the books of the Corporation, and the holders shall have no interest in or claim against the Corporation with respect to the shares, but shall be entitled only to receive the redemption price from the bank or trust company, or from the Corporation, without interest, upon surrender of the certificates.
(4) The term "accrued dividends," as used in this Article, shall mean, in respect of any share of the 1965 Series Preferred Stock as of any given date, the amount of dividends payable on the share, whether or not earned or declared, computed, at the annual dividend rate fixed for the share, from the date on which dividends on the share became cumulative through the given date, less the aggregate amount of all dividends which have been paid or which have been declared and set apart for payment on the share. Accumulations of dividends shall not bear interest.
(5) Upon the redemption of shares of the 1965 Series Preferred Stock, the shares shall resume the status which they had prior to the adoption by the Board of Directors of resolutions creating the series, as provided in section B of this Article and shall thereafter have the status of authorized but unissued shares of the Preferred Stock of the Corporation and may be reissued from time to time upon adoption of a resolution or resolutions by the Board of Directors of the Corporation creating a new series of Preferred Stock or increasing the number of shares constituting any series of Preferred Stock then outstanding, as provided in section B and subject to the provisions of section F.
(6) Nothing contained in this section shall limit any legal right of the Corporation to purchase any shares of the 1965 Series Preferred Stock.
F.(1) So long as any shares of 1965 Series Preferred Stock are outstanding, the Corporation shall not, without the affirmative vote of the holders of at least two-thirds of the outstanding shares of 1965 Series Preferred Stock:
(a) Amend the provisions of the Articles of Incorporation so as to create or authorize any stock ranking prior in any respect to the 1965 Series Preferred Stock; or issue any such stock; or
(b) Change, by amendment to the Articles of Incorporation, or otherwise, the terms and provisions of the 1965 Series Preferred Stock so as to affect adversely the rights and preferences of the holders.
No consent of the holders of the 1965 Series Preferred Stock shall be required in respect of any transaction enumerated in this subsection (1) if at or prior to the time when the transaction is to take effect provision is made for the redemption or other retirement of all shares of 1965 Series Preferred Stock at the time outstanding, the consent of which would otherwise be required.
(2) So long as any shares of the 1965 Series Preferred Stock are outstanding, the Corporation shall not, without the affirmative vote of the holders of a majority of the total number of shares of 1965 Series Preferred Stock then outstanding:
(a) Issue any shares of the 1965 Series Preferred Stock or shares of any stock ranking on a parity with the 1965 Series Preferred Stock,
other than in exchange for, or for the purpose of effecting the redemption or other retirement of, shares having an aggregate redemption price approximately equal to the redemption price of the shares being issued, unless:
(I) the net income (determined in accordance with accepted accounting principles) of the Corporation available for the payment of dividends shall, for a period of twelve consecutive calendar months within the fifteen calendar months next preceding the issue of the shares, have been at least two (2) times an amount equal to the dividend requirements for one year on all shares of the 1965 Series Preferred Stock and on all other shares of stock, if any, ranking prior to or on a parity with the 1965 Series Preferred Stock, which shall be outstanding after the issue of the shares proposed to be issued; and
(II) the gross income after federal income taxes
(determined in accordance with accepted accounting principles)
of the Corporation available for the payment of interest charges
shall, for a period of twelve consecutive calendar months within
the fifteen calendar months next preceding the issue of the
shares, have been at least one and one-half (1 1/2) times the
aggregate, for a twelve months period, of the dividend
requirement and the annual interest charges on all funded
indebtedness and notes payable of the Corporation maturing more
than twelve months after, and outstanding at, the date of the
issue of the shares; and
(III) the capital represented by the Common Stock and the surplus accounts of the Corporation shall be not less than the aggregate amount payable on the involuntary dissolution, liquidation or winding up of the Corporation, in respect of all shares of the 1965 Series Preferred Stock and all shares of stock, if any, of equal or prior ranking, which shall be outstanding after the issue of the shares proposed to be issued.
(b) Issue or assume any unsecured debentures or other unsecured indebtedness, but excluding unsecured indebtedness maturing within eighteen months after issuance, for any purpose other than the refunding of secured or unsecured indebtedness previously created or assumed by the Corporation and then outstanding, or the retiring, by redemption or otherwise, of shares of the 1965 Series Preferred Stock or shares of any stock of equal or prior ranking, if
(I) immediately after the issue or assumption the total amount of all indebtedness of the Corporation, both secured and unsecured indebtedness due more than one year after issuance shall exceed sixty-five per cent (65%) of the aggregate of (i) the total amount of all indebtedness maturing more than one year from the date as of which that unsecured indebtedness will be issued, and then outstanding, and (ii) the total of the capital and surplus of the corporation, as then recorded on its books; and
(II) the gross income after federal income taxes
(determined in accordance with accepted accounting principles)
of the Corporation available for the payment of interest charges
shall not, for a period of twelve consecutive calendar months
within the fifteen calendar months next preceding the issue of
the unsecured debentures, have been at least one and three
quarters (1 3/4) times the aggregate of the dividend
requirements for one year on all shares of the 1965 Series
Preferred Stock and on all other shares of stock, if any, of
equal or prior ranking to the 1965 Series Preferred Stock, which
shall be then outstanding, and the annual interest charges on all funded indebtedness and notes payable of the Corporation maturing more than twelve months after, and outstanding at, the date of the issue of the unsecured debentures or other unsecured indebtedness.
No consent of the holders of 1965 Series Preferred Stock shall
be required in respect of any transaction enumerated in this subsection
(2) if, at or prior to the time when the transaction is to take effect,
provision is made for the redemption or other retirement of all shares
of the 1965 Series Preferred Stock at the time outstanding, the consent
of which would otherwise be required.
No provision contained in this section is intended or shall be construed to relieve the Corporation from compliance with any applicable statutory provision requiring the vote or consent of a greater number of the outstanding shares of the 1965 Series Preferred Stock.
G. So long as any shares of the 1965 Series Preferred Stock are outstanding, the Corporation shall not declare or pay any dividends on its Common Stock (other than dividends payable in Common Stock) or make any distribution on, or purchase or otherwise acquire for value, any of its Common Stock (each such payment, distribution, purchase or acquisition being referred to as a "common stock dividend"), except to the extent permitted by the following provisions of this section:
(a) No common stock dividend shall be declared or paid in an amount which, together with all other common stock dividends declared in the twelve consecutive calendar months ended with and including the calendar month in which the proposed declaration is made, would in the aggregate exceed fifty per cent (50%) of the net income of the Corporation available for dividends on its Common Stock for the twelve consecutive calendar months ending on the last day of the calendar month next preceding the declaration of the common stock dividend, if at the end of the calendar month the ratio ("capitalization ratio") of the sum of (i) the capital represented by the Common Stock (including premiums on Common Stock) and (ii) the surplus accounts, of the Corporation, to the sum of (x) the total capital and (xx) the surplus accounts, of the Corporation (after adjustment, in each case, of the surplus accounts to reflect payment of the common stock dividend) would be less than twenty per cent (20%);
(b) If the capitalization ratio shall be twenty per cent (20%) or more, but less than twenty-five per cent (25%), no common stock dividend shall be declared or paid in an amount which, together with all other common stock dividends declared in the twelve consecutive calendar months ended with and including the calendar month in which the proposed declaration is made, would exceed seventy-five per cent (75%) of the net income of the corporation available for dividends on its Common Stock for the twelve consecutive calendar months ending on the last day of the calendar month next preceding the declaration of the common stock dividend; and
(c) If the capitalization ratio shall be twenty-five per cent (25%) or more, no common stock dividend shall be declared or paid which would reduce capitalization ratio to less than twenty-five per cent (25%) except to the extent permitted by paragraphs (a) and (b) of this section.
For the purpose of paragraphs (a), (b) and (c): (i) the net income of the Corporation available for dividends on its Common Stock for any twelve month period is to be computed after deducting an amount equal to dividends accrued for the twelve month period on shares of stock having preference as to dividends over the Common Stock and (ii) the total capital of the Corporation shall be deemed to consist of the aggregate of (x) the principal amount of all outstanding indebtedness of the Corporation maturing one year or more after the date of issue and (xx) the par or stated value of all outstanding capital stock (including premiums on capital stock) of all classes of the Corporation. All indebtedness and capital stock owned by the Corporation shall be excluded in determining total capital. Surplus accounts shall be deemed to include all earned surplus, paid in surplus, capital surplus or any other surplus of the Corporation. Purchases or other acquisitions of Common Stock shall be deemed, for the purpose of this section, to have been made as of the date on which the purchases or acquisitions are consummated.
H. No holder of the 1965 Series Preferred Stock shall be entitled to vote for the election of directors or in respect of any matter, except as provided in section F of this Article or in this section, or as may be required by law. If, however, dividends payable on the outstanding 1965 Series Preferred
Stock shall be accumulated and unpaid in an amount equivalent to four (4) quarterly dividends, the holders of the stock shall be entitled, until all accumulated and unpaid dividends shall have been fully paid or declared and funds set apart for payment: (a) voting for as a single class, at the next annual meeting of stockholders, to elect one third of the directors to be elected at that annual meeting of stockholders and at the following annual meeting of stockholders, if dividends payable on the outstanding 1965 Series Preferred Stock continue to be due and unpaid, to elect a majority of the directors to be elected at that annual meeting of stockholders, and to continue to elect a majority of the Board of Directors until all accumulated and unpaid dividends on the outstanding 1965 Series Preferred Stock shall have been paid; and (b) to vote on all questions so that the holders shall have one (1) vote for each ten dollars ($10) of stated value per share of 1965 Series Preferred Stock (stated values not equaling dollar increments shall be rounded up to the next ten dollar increment for these purposes), and this right to vote shall not be cumulative; provided that if and when profits available for dividends are in excess of accumulated and unpaid dividends, then the declaration and payment of the dividends shall not be unreasonably withheld.
In consideration of the issue by the Corporation, and the purchase by the holders, of shares of the capital stock of the Corporation, each and every present and future holder of shares of the capital stock of the Corporation shall be conclusively deemed, by acquiring or holding the shares, to have expressly consented to each and every term and provision of this section and to have agreed that the voting rights of the holder and their restrictions and qualifications shall be as set forth in this section.
I. No share of stock or evidence of indebtedness shall be deemed to be "outstanding" as that term is used in the Articles of Incorporation, as amended, if, prior to or concurrently with the event in reference to which a determination as to the amount outstanding is to be made, the requisite funds for its redemption shall be deposited in trust for that purpose and the requisite notice for its redemption shall be given or the depositary of the funds shall be irrevocably authorized and directed to give or complete the notice of redemption."
II. This amendment was adopted by the shareholders on May 17, 2002.
III. The number of shares outstanding and entitled to vote on the amendment was 39,117,799.
IV. The number of shares voting in favor of the amendment was 39,117,799 with no votes being cast against and no votes abstaining.
PUBLIC SERVICE COMPANY OF NEW MEXICO
By: /s/ Jeffry E. Sterba
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JEFFRY E. STERBA
Chairman, President and Chief
Executive Officer
DATED: May 17, 2002
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Exhibit 3.1.2
BYLAWS
PUBLIC SERVICE COMPANY OF NEW MEXICO
As Adopted and Amended May 31, 2002
BYLAWS
OF
PUBLIC SERVICE COMPANY OF NEW MEXICO
Special meetings may be called by a majority of the Board of Directors, the Chairman of the Board, the President or by holders of not less than one-tenth of all the shares entitled to vote at the meeting.
(b) The Chairman of the meeting shall have the right to determine the order of business at the meeting, to prescribe the rules and procedures for the conduct of the meeting, and to do all things necessary or desirable for the proper conduct of the meeting.
In all elections for directors, voting may be by written ballot.
The Board of Directors may fix a date in advance not exceeding thirty
(30) days before the date of any meeting of shareholders as a record date for
the determination of shareholders entitled to notice of and to vote at the
meeting. Only shareholders of record on the date so fixed shall be entitled to
notice of and to vote at the meeting.
terms and duties of office. A vacancy occurring in any office of a Vice President may be filled by the Board of Directors. All Vice Presidents shall hold office at the discretion of the Board of Directors and shall be subject to removal at any time by the affirmative vote of a majority of the whole Board of Directors. Election of any person as an officer of the Corporation shall not of itself create contract rights. The Board may appoint as officers persons who are not employees of the Corporation, with the consent of the shareholders.
All other Vice Presidents shall be responsible for the areas and activities assigned by the President and shall perform other duties as may be required, including those assigned to an Executive or Senior Vice President during the absence or incapacity of the Executive or Senior Vice President.
In making any appointments of assistants, the Secretary, Treasurer and Controller shall use the following form:
I, ________________ (Name), the duly elected _______________ (Title) of Public Service Company of New Mexico do hereby appoint ________________ (Name) to serve as Assistant __________________(Title)for the period of __________(Date) to __________ (Date), unless this appointment is terminated earlier in writing, to assume or perform all functions and duties which I might require and, in my absence or incapacity, which I might lawfully do if present and not under any incapacity.
Any appointments of assistants by the Secretary, Treasurer or Controller and any terminations of appointments shall be maintained in the records of the Secretary's office.
In lieu of closing the stock transfer books, the Board of Directors may, by resolution, fix in advance a date as the record date for any determination of shareholders, the date to be not more than thirty (30) days and, in case of a meeting of shareholders, not less than ten (10) days prior to the date on which the action requiring the determination of shareholders is to be taken.
The Board of Directors is not authorized to alter, amend or repeal the provisions of the Corporation's Bylaws relating to the number of directors, compensation of directors, selection of the Chairman of the Board of Directors, and selection of the President.
EXHIBIT 99.1
CERTIFICATION PURSUANT TO 18 U.S.C.ss.1350, AS ADOPTED PURSUANT
TOss.906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report on Form 10Q for the period ending June 30, 2002, for PNM Resources, Inc. and Public Service Company of New Mexico ("Companies"), as filed with the Securities and Exchange Commission on August 14, 2002, ("Report"), I, Jeffry E. Sterba, Chief Executive Officer of the Companies, certify pursuant to 18 U.S.C. ss.1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:
(1) the Report fully complies with the requirements of ss. 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Companies.
Date: ___________________ By: ___________________________
Jeffry E. Sterba
Chief Executive Officer
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EXHIBIT 99.2
CERTIFICATION PURSUANT TO 18 U.S.C.ss.1350, AS ADOPTED PURSUANT
TOss.906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report on Form 10Q for the period ending June 30, 2002, for PNM Resources, Inc. and Public Service Company of New Mexico ("Companies"), as filed with the Securities and Exchange Commission on August 14, 2002, ("Report"), I, Max H. Maerki, Chief Financial Officer of the Companies, certify pursuant to 18 U.S.C. ss.1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:
(1) the Report fully complies with the requirements of ss. 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Companies.
Date: ___________________ By: ___________________________
Max H. Maerki
Chief Financial Officer
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