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, 2000
--------------
- OR -
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _________________
Commission file number 1-6986
------
PUBLIC SERVICE COMPANY OF NEW MEXICO
------------------------------------
(Exact name of registrant as specified in its charter)
New Mexico 85-0019030
---------- -----------
(State or other jurisdiction of (I.R.S. Employer
Incorporation of organization) Identification No.)
Alvarado Square, Albuquerque, New Mexico 87158
----------------------------------------------
(Address of principal executive offices)
(Zip Code)
(505) 241-2700
--------------
(Registrant's telephone number, including area code)
------------------------------
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common Stock-$5.00 par value 39,535,699 shares
---------------------------- -----------------
Class Outstanding at August 1, 2000
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
INDEX
Page No.
PART I. FINANCIAL INFORMATION:
Report of Independent Public Accountants.......................... 3
ITEM 1. FINANCIAL STATEMENTS
Consolidated Statements of Earnings -
Three Months and Six Months Ended June 30, 2000 and 1999.......... 4
Consolidated Balance Sheets -
June 30, 2000 and December 31, 1999............................... 5
Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2000 and 1999........................... 7
Notes to Consolidated Financial Statements........................ 8
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS............ 20
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.............................................. 53
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS........................................... 54
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS.................................................. 57
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................ 58
Signature ......................................................... 59
2
<PAGE>
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, 2000 and the related condensed consolidated statements of earnings for
the three-month and six-month periods ended June 30, 2000 and 1999, and the
condensed consolidated statements of cash flows for the six-month periods ended
June 30, 2000 and 1999. 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, 1999, and the related consolidated statements of earnings,
capitalization and cash flows for the year then ended (not presented separately
herein), and in our report dated January 26, 2000, 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,
1999, 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 11, 2000
3
<PAGE>
ITEM 1. FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- -------------------
2000 1999 2000 1999
--------- -------- -------- --------
(In thousands, except per share amounts)
<S> <C> <C> <C> <C>
Operating Revenues:
Electric ............................... $273,184 $212,864 $499,580 $397,306
Gas .................................... 54,514 48,319 149,060 133,183
Unregulated businesses ................. 1,343 188 1,692 3,700
-------- -------- -------- --------
Total operating revenues ............. 329,041 261,371 650,332 534,189
-------- -------- -------- --------
Operating Expenses:
Cost of energy sold .................... 180,394 107,954 348,117 218,363
Energy production costs ................ 35,906 35,207 71,548 69,401
Administrative and general ............. 33,562 35,361 65,758 72,266
Depreciation and amortization .......... 22,633 23,345 46,642 46,426
Transmission and distribution costs .... 14,795 15,236 30,076 29,513
Taxes, other than income taxes ......... 8,465 8,848 16,131 18,169
Income taxes............................ 5,632 6,173 13,459 15,736
-------- -------- -------- --------
Total operating expenses ............. 301,387 232,124 591,731 469,874
-------- -------- -------- --------
Operating income ..................... 27,654 29,247 58,601 64,315
-------- -------- -------- --------
Other Income and Deductions, Net of Tax... 6,753 6,313 14,258 12,412
-------- -------- -------- --------
Income before interest charges ....... 34,407 35,560 72,859 76,727
-------- -------- -------- --------
Interest Charges:
Interest on long-term debt ............. 15,676 16,688 31,457 33,402
Other interest charges ................. 745 700 1,464 2,023
-------- -------- -------- --------
Net interest charges ................. 16,421 17,388 32,921 35,425
-------- -------- -------- --------
Net Earnings from Continuing Operations 17,986 18,172 39,938 41,302
Cumulative Effect of a Change in
Accounting Principle, Net of Tax ....... -- -- -- 3,541
-------- -------- -------- --------
Net Earnings ............................. 17,986 18,172 39,938 44,843
Preferred Stock Dividend Requirements .... 147 146 293 293
-------- -------- -------- --------
Net Earnings Applicable to Common Stock $ 17,839 $ 18,026 $ 39,645 $ 44,550
======== ======== ======== ========
Net Earnings per Common Share:
Basic .................................. $ 0.45 $ 0.44 $ 1.00 $ 1.08
======== ======== ======== ========
Diluted ................................ $ 0.45 $ 0.44 $ 1.00 $ 1.08
======== ======== ======== ========
Dividends Paid per Share of Common Stock.. $ 0.20 $ 0.20 $ 0.40 $ 0.40
======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
4
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2000 1999
----------- ----------
(Unaudited)
ASSETS (In thousands)
------
<S> <C> <C>
Utility Plant:
Electric plant in service .............................. $1,976,764 $1,976,009
Gas plant in service ................................... 485,558 483,819
Common plant in service and plant held for future use .. 69,300 69,273
---------- ----------
2,531,622 2,529,101
Less accumulated depreciation and amortization ......... 1,119,723 1,077,576
---------- ----------
1,411,899 1,451,525
Construction work and progress ......................... 139,233 104,934
Nuclear fuel, net of accumulated amortization of
$20,140 and $20,832 ................................. 25,782 25,923
---------- ----------
Net utility plant .................................... 1,576,914 1,582,382
---------- ----------
Other Property and Investments:
Other investments ...................................... 477,571 483,008
Non-utility property, net of accumulated depreciation
of $1,466 and $1,261 ............................... 3,804 4,439
---------- ----------
Total other property and investments ................. 481,375 487,447
---------- ----------
Current Assets:
Cash and cash equivalents .............................. 84,060 120,399
Accounts receivables, net of allowance for
uncollectible accounts of $8,935 and $12,504 ....... 173,221 147,746
Other receivables ...................................... 59,962 68,911
Inventories ............................................ 33,951 33,064
Regulatory assets ...................................... 8,749 24,056
Other current assets ................................... 59,164 11,862
---------- ----------
Total current assets ................................. 419,107 406,038
---------- ----------
Deferred Charges:
Regulatory assets ...................................... 211,550 195,898
Prepaid benefit costs .................................. 17,121 16,126
Other deferred charges ................................. 47,203 35,377
---------- ----------
Total current assets ................................. 275,874 247,401
---------- ----------
$2,753,270 $2,723,268
========== ==========
</TABLE>
5
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2000 1999
---------- -----------
(Unaudited)
CAPITALIZATION AND OTHER LIABILITIES (In thousands)
------------------------------------
<S> <C> <C>
Capitalization:
Common stockholders' equity:
Common stock ............................................... $ 197,678 $ 203,517
Additional paid-in capital ................................. 440,371 453,393
Accumulated other comprehensive income, net of tax ......... 1,790 2,352
Retained earnings .......................................... 251,768 227,829
---------- ----------
Total common stockholders' equity ....................... 891,607 887,091
Minority interest ............................................. 12,482 12,771
Cumulative preferred stock without mandatory
Redemption requirements .................................. 12,800 12,800
Long-term debt, less current maturities ....................... 953,792 988,489
---------- ----------
Total capitalization .................................... 1,870,681 1,901,151
---------- ----------
Current Liabilities:
Accounts payable .............................................. 149,406 150,645
Accrued interest and taxes .................................... 33,210 34,237
Other current liabilities ..................................... 122,091 60,948
---------- ----------
Total current liabilities ............................... 304,707 245,830
---------- ----------
Deferred Credits:
Accumulated deferred income taxes ............................... 151,421 153,179
Accumulated deferred investment tax credits ..................... 49,425 50,996
Regulatory liabilities .......................................... 82,711 88,497
Regulatory liabilities related to accumulated deferred
income tax .................................................... 15,091 15,091
Accrued postretirement benefit costs ............................ 10,623 8,945
Other deferred credits .......................................... 268,611 259,579
---------- ----------
Total deferred credits ....................................... 577,882 576,287
---------- ----------
Commitments and Contingencies ..................................... -- --
---------- ----------
$2,753,270 $2,723,268
========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
6
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
----------------------
2000 1999
--------- ---------
(In thousands)
<S> <C> <C>
Cash Flows From Operating Activities:
Net earnings .................................................... $ 39,938 $ 44,843
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization ............................... 51,930 52,064
Gain on cumulative effect of a change in accounting principle -- (5,862)
Other, net .................................................. 8,469 1,031
Changes in certain assets and liabilities:
Accounts receivables ...................................... (25,475) (230)
Other assets .............................................. 7,714 5,364
Accounts payable .......................................... (1,239) (21,639)
Other liabilities ......................................... 15,533 12,104
--------- ---------
Net cash flows provided from operating activities ......... 96,870 87,675
--------- ---------
Cash Flows From Investing Activities:
Utility plant additions ......................................... (50,365) (38,932)
Return on PVNGS lease obligation bonds .......................... 8,636 9,029
Other investing ................................................. (23,311) 24,112
--------- ---------
Net cash flows used from investing activities ............. (65,040) (5,791)
--------- ---------
Cash Flows From Financing Activities:
Repayments ...................................................... (32,800) (47,744)
Common stock repurchase ......................................... (18,854) (17,651)
Dividends paid .................................................. (16,227) (16,739)
Other financing ................................................. (288) (369)
--------- ---------
Net cash flows used in financing activities ............... (68,169) (82,503)
--------- ---------
Decrease in Cash and Cash Equivalents ............................. (36,339) (619)
Beginning of Period ............................................... 120,399 61,280
--------- ---------
End of Period ..................................................... $ 84,060 $ 60,661
========= =========
Supplemental Cash Flow Disclosures:
Interest paid ................................................... $ 32,854 $ 34,645
========= =========
Income taxes paid, net .......................................... $ 20,423 $ 24,425
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
7
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies and Responsibilities for Financial Statements
In the opinion of management of Public Service Company of New Mexico (the
"Company"), the accompanying interim consolidated financial statements present
fairly the Company's financial position at June 30, 2000 and December 31, 1999,
the consolidated results of its operations for the three months ended June 30,
2000 and the consolidated statements of cash flows for the three months ended
March 31, 2000. These statements are presented in accordance with the rules and
regulations of the United States Securities and Exchange Commission ("SEC").
Accordingly, they are unaudited, and certain information and footnote
disclosures normally included in the Company's annual consolidated financial
statements have been condensed or omitted, as permitted under the applicable
rules and regulations. Readers of these statements should refer to the Company's
audited consolidated financial statements and notes thereto for the year ended
December 31, 1999, which are included on the Company's Annual Report on Form
10-K for the year ended December 31, 1999. The results of operations presented
in the accompanying financial statements are not necessarily representative of
operations for an entire year.
Certain amounts in the 1999 consolidated financial statements and notes have
been reclassified to conform to the 2000 financial statement presentation.
(2) Segment Information
The Company has three principal business segments. The utility segment consists
of three major business lines that include the Electric Service Business Unit
("Distribution"), Transmission Service Business Unit ("Transmission") and
Natural Gas Distribution and Transmission Business Unit ("Gas"). The Generation
business segment includes the Company's physical electric generation operations
as well as the Company's electric trading operations. The unregulated segment
consists of the operations of Avistar, Inc. and certain corporate administrative
functions. Intersegment revenues are determined based on a formula mutually
agreed upon between affected segments and are not based on market rates.
Intersegment revenues are eliminated for consolidated purposes.
8
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(2) Segment Information (Continued)
Summarized financial information by business segment for the three months and
six months ended June 30, 2000 and 1999 is as follows:
<TABLE>
<CAPTION>
Utility
----------------------------------------------------
Distribution Transmission Gas Total Generation Unregulated Consolidated
------------ ------------ --- ----- ---------- ----------- ------------
(In thousands)
Three Months Ended:
------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2000:
Operating revenues:
External customers............. $126,141 $ 4,002 $ 54,514 $ 184,657 $ 143,041 $ 1,343 $ 329,041
Intersegment revenues.......... - 7,064 - 7,064 78,869 - 85,933
Depreciation and amortization..... 5,849 2,104 4,515 12,468 10,159 6 22,633
Interest income (loss)............ 350 (3) 110 457 9,743 2,171 12,371
Net interest charges.............. 3,332 1,051 2,881 7,264 8,887 270 16,421
Income tax expense (benefit)
From continuing operations...... 6,504 531 (427) 6,608 6,853 (3,776) 9,685
Operating income (loss)........... 13,488 1,976 1,961 17,425 16,669 (6,440) 27,654
Segment net income (loss)......... 10,093 897 (836) 10,154 12,959 (5,127) 17,986
Total assets...................... 545,500 200,276 442,892 1,188,668 1,449,638 120,659 2,758,965
Gross property additions.......... 9,454 2,638 6,475 18,567 9,438 2,335 30,340
1999:
Operating revenues:
External customers............. $133,191 $ 3,736 $ 48,319 $ 185,246 $ 75,937 $ 188 $ 261,371
Intersegment revenues.......... - 7,450 - 7,450 79,198 - 86,648
Depreciation and amortization..... 5,670 2,062 4,722 12,454 10,370 521 23,345
Interest income................... 5 - 195 200 10,170 2,146 12,516
Net interest charges.............. 3,887 1,245 3,060 8,192 8,955 241 17,388
Income tax expense (benefit)
from continuing operations...... 6,864 605 (294) 7,175 6,053 (2,918) 10,310
Operating income (loss)........... 14,689 2,244 2,599 19,532 13,489 (3,774) 29,247
Segment net income (loss)......... 10,540 978 (639) 10,879 11,746 (4,453) 18,172
Total assets...................... 555,843 185,096 397,856 1,138,795 1,247,029 162,996 2,548,820
Gross property additions.......... 6,165 3,231 5,493 14,889 6,207 585 21,681
</TABLE>
9
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(2) Segment Information (Continued)
Summarized financial information by business segment for the three months and
six months ended June 30, 2000 and 1999 is as follows:
<TABLE>
<CAPTION>
Utility
----------------------------------------------------
Distribution Transmission Gas Total Generation Unregulated Consolidated
------------ ------------ --- ----- ---------- ----------- ------------
(In thousands)
Six Months Ended:
----------------
<S> <C> <C> <C> <C> <C> <C> <C>
2000:
Operating revenues:
External customers............. $248,250 $ 7,813 $149,060 $405,123 $243,517 $ 1,692 $650,332
Intersegment revenues.......... - 13,861 - 13,861 154,691 - 168,552
Depreciation and amortization..... 12,306 4,207 9,881 26,394 20,237 11 46,642
Interest income................... 390 3 247 640 19,522 3,436 23,598
Net interest charges.............. 6,705 2,148 5,735 14,588 17,787 546 32,921
Income tax expense (benefit)
From continuing operations...... 11,940 999 3,299 16,238 12,666 (6,518) 22,386
Operating income (loss)........... 25,477 3,879 10,079 39,435 30,475 (11,309) 58,601
Segment net income (loss)......... 18,557 1,699 4,664 24,920 24,329 (9,311) 39,938
Total assets...................... 545,500 200,276 442,892 1,188,668 1,449,638 120,659 2,758,965
Gross property additions.......... 17,458 4,479 11,212 33,149 17,216 2,834 53,199
1999:
Operating revenues:
External customers............. $262,374 $ 7,512 $133,183 $403,069 $127,420 $ 3,700 $534,189
Intersegment revenues.......... - 14,900 - 14,900 157,168 - 172,068
Depreciation and amortization..... 11,323 4,125 9,404 24,852 20,533 1,041 46,426
Interest income................... 16 3 395 414 20,447 3,510 24,371
Net interest charges.............. 7,940 2,546 6,229 16,715 18,209 501 35,425
Income tax expense (benefit)
from continuing operations...... 12,816 1,308 2,856 16,980 11,285 (4,395) 23,870
Operating income (loss)........... 28,005 4,696 10,928 43,629 27,050 (6,364) 64,315
Cumulative effect of a change in
accounting principle, net of tax - - - - 3,541 - 3,541
Segment net income (loss)......... 19,685 2,108 3,976 25,769 25,780 (6,706) 44,843
Total assets...................... 555,843 185,096 397,856 1,138,795 1,247,029 162,996 2,548,820
Gross property additions.......... 13,004 5,055 10,665 28,724 10,208 890 39,822
</TABLE>
10
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(3) Comprehensive Income
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2000 1999 2000 1999
-------- -------- -------- --------
(In thousands)
<S> <C> <C> <C> <C>
Net Earnings .................................... $ 17,986 $ 18,172 $ 39,938 $ 44,843
-------- -------- -------- --------
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains arising during
the period .............................. 614 384 1,940 1,672
Less reclassification adjustment for
gains included in net income .......... (1,153) (1,339) (2,503) (2,161)
-------- -------- -------- --------
Total Other Comprehensive Income (Loss) ...... (539) (955) (563) (489)
-------- -------- -------- --------
Total Comprehensive Income ...................... $ 17,447 $ 17,217 $ 39,375 $ 44,354
======== ======== ======== ========
</TABLE>
The Company's investments held in grantor trusts for nuclear decommissioning and
certain retirement benefits are classified as available-for-sale, and
accordingly unrealized holding gains and losses are recognized as a component of
comprehensive income. Realized gains and losses are included in earnings. All
components of comprehensive income are recorded, net of any tax benefit or
expense. A deferred asset or liability is established for the resulting
temporary difference.
(4) Financial Instruments
The Company uses derivative financial instruments in limited instances to manage
risk as it relates to changes in natural gas and electric prices and adverse
market changes for investments held by the Company's various trusts. The Company
also uses certain derivative instruments for bulk power electricity trading
purposes in order to take advantage of favorable price movements and market
timing activities in the wholesale power markets.
The Company is exposed to credit losses in the event of non-performance or
non-payment by counterparties. The Company uses a credit management process to
assess and monitor the financial conditions of counterparties. The Company's
credit risk with its largest counterparty as of June 30, 2000 was $33.7 million.
11
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4) Financial Instruments (Continued)
Natural Gas Contracts
Pursuant to an order issued by the NMPUC, predecessor to the PRC, the Company
has previously entered into swaps to hedge certain portions of natural gas
supply contracts in order to protect the Company's natural gas customers from
the risk of adverse price fluctuations in the natural gas market. The financial
impact of all hedge gains and losses from swaps flowed through the Company's
purchased gas adjustment clause and are fully recoverable by the Company. As a
result, earnings were not affected by gains or losses generated by these
instruments. The Company hedged 40% of its natural gas deliveries during the
1998-1999 heating season. Less than 15.5% of the 1998-1999 heating season
portfolio was hedged using financial hedging contracts. The Company hedged a
portion of its 1999-2000 heating season gas supply portfolio through the use of
both physical and financial hedging tools. Less than 9.1% of the Company's
1999-2000 heating season portfolio was hedged using financial hedging contracts.
The 1999-2000 heating season hedges were completed in January 2000.
The Company intends to hedge its 2000-2001 heating season gas supply portfolio
through the use of financial hedging tools. Pursuant to an agreement with the
PRC, the Company will limit its hedging strategy to a cost of $5 million.
Fuel Hedging
Subsequent to June 30, 2000, the Company's Generation Operations commenced a
program to reduce its exposure to fluctuations in prices for gas and oil
purchases used as a fuel source for some of its generation. The Generation
Operations purchased futures contracts for a portion of its anticipated natural
gas needs in the third quarter and fourth quarter. The futures contracts cap the
Company's natural gas purchase prices at $3.70 to $3.99 per MMBTU and have a
notional principal $4.5 million. Simultaneously, a delivery location basis swap
was purchased for quantities corresponding to the futures quantities to protect
against price differential changes at the specific delivery points. The
financial instruments will settle in the third quarter and fourth quarter. The
Company will account for these transactions as hedges; accordingly, gains and
losses related to these transactions will be deferred and recognized in earnings
as an adjustment to its cost of fuel.
12
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4) Financial Instruments (Continued)
Electricity Trading Contracts
To take advantage of market opportunities associated with the purchase and sale
of electricity, the Company's wholesale power operation periodically enters into
derivative financial instrument contracts. In addition, the Company enters into
forward physical contracts and physical options. The Company generally accounts
for these financial instruments as trading activities under the accounting
guidelines set forth under The Emerging Issues Task Force ("EITF") Issue No.
98-10. Although at times, the Company may enter into contracts that it may
designate as hedges. As a result, all open contracts are marked to market at the
end of each period. The physical contracts are subsequently recognized as
revenues or purchased power when the actual physical delivery occurs. The
Company implemented EITF Issue No. 98-10 as of January 1, 1999 and recorded as a
cumulative effect of a change in accounting principle a gain of approximately
$3.5 million, net of taxes, or $0.09 per common share, on net open physical
electricity purchases and sales commitments considered to be trading activities.
Through June 30, 2000, the Company's wholesale electric trading operations
settled trading contracts for the sale of electricity that generated $42.2
million of electric revenues by delivering 1,286 million KWh. The Company
purchased $40.5 million or 1,236 million KWh of electricity to support these
contractual sale and other open market sales opportunities.
As of June 30, 2000, the Company had open trading contract positions to buy
$34.1 million and to sell $41.2 million of electricity. At June 30, 2000, the
Company had a gross mark-to-market gain (asset position) on these trading
contracts of $51.7 million and gross mark-to-market loss (liability position) of
$65.6 million, with net mark-to-market loss (liability position) of $13.8
million. Although the Company has classified these contracts as trading, the
Company expects to cover its net open contract positions with its own excess
generating capacity which is not marked-to-market. The mark-to-market valuation
is recognized in earnings each period.
13
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4) Financial Instruments (Continued)
Hedge of Trust Assets
The Company has about $44 million invested in domestic stocks in various trusts
for nuclear decommissioning, executive retirement and retiree medical benefits.
The Company uses financial derivatives based on the Standard & Poor's ("S&P")
500 Index to limit potential loss on these investments due to adverse market
fluctuations. The options are structured as a collar, protecting the portfolio
against losses beyond a certain amount and balancing the cost of that downside
protection by foregoing gains above a certain level. If the S&P 500 Index is
within the specified range when the option contract expires, the Company will
not be obligated to pay, nor will the Company have the right to receive cash. In
February 2000, certain contracts were terminated. The Company recognized a
realized gain of $2.4 million (pre-tax) on these terminations. Subsequently, the
Company entered into similar contracts which expire on June 15, 2001. For the
three months ended June 30, 2000, the Company recorded net unrealized gains of
$1.2 million (pre-tax) and for the six months ended June 30, 2000, the Company
recorded net unrealized losses of $0.5 million (pre-tax) on the market value of
its options. The net effect of the collar instruments for the six months ended
June 30, 2000 was a net pre-tax gain of $1.9 million.
14
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(5) Earnings Per Share
In accordance with SFAS No. 128, Earnings per Share, dual presentation of basic
and diluted earnings per share has been presented in the Consolidated Statements
of Earnings. The following reconciliation illustrates the impact on the share
amounts of potential common shares and the earnings per share amounts for June
30 (in thousands, except per share data):
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
2000 1999 2000 1999
------- ------- ------- -------
Basic:
<S> <C> <C> <C> <C>
Net Earnings from Continuing Operations ............... $17,986 $18,172 $39,938 $41,302
Cumulative Effect of a Change in Accounting
Principle, net of tax .............................. -- -- -- 3,541
------- ------- ------- -------
Net Earnings .......................................... 17,986 18,172 39,938 44,843
Preferred Stock Dividend Requirements ................. 147 146 293 293
------- ------- ------- -------
Net Earnings Applicable to Common Stock ............... $17,839 $18,026 $39,645 $44,550
======= ======= ======= =======
Average Number of Common Shares Outstanding ........... 39,536 40,852 39,754 41,307
======= ======= ======= =======
Net Earnings per Common Share:
Earnings from continuing operations ................. $ 0.45 $ 0.44 $ 1.00 $ 0.99
Cumulative effect of a change in accounting
principle ......................................... -- -- -- 0.09
------- ------- ------- -------
Net Earnings per Common Share (Basic) ................. $ 0.45 $ 0.44 $ 1.00 $ 1.08
======= ======= ======= =======
Diluted:
Net Earnings Applicable to Common Stock
Used in basic calculation ........................... $17,839 $18,026 $39,645 $44,550
======= ======= ======= =======
Average Number of Common Shares Outstanding ........... 39,536 40,852 39,754 41,307
Diluted effect of common stock equivalents (a) ........ 61 86 45 65
------- ------- ------- -------
Average common and common equivalent shares
Outstanding ......................................... 39,597 40,938 39,799 41,372
======= ======= ======= =======
Net Earnings per Common Share:
Earnings from continuing operations ................. $ 0.45 $ 0.44 $ 1.00 $ 0.99
Cumulative effect of a change in accounting
principle ......................................... -- -- -- 0.09
------- ------- ------- -------
Net Earnings per Share of Common Stock (Diluted) ...... $ 0.45 $ 0.44 $ 1.00 $ 1.08
======= ======= ======= =======
<FN>
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out of-the-money options of 141,660 and 43,756 for the three
months ended 2000 and 1999, respectively and 162,066 and 59,749 for the six
months ended 2000 and 1999, respectively.
</FN>
</TABLE>
15
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies
New Customer Billing System
On November 30, 1998, the Company implemented a new customer billing system. Due
to a significant number of problems associated with the implementation of the
new billing system, the Company was unable to generate appropriate bills for
certain of its customers through the first quarter of 1999 and was unable to
analyze delinquent accounts until November 1999.
As a result of the delay of normal collection activities, the Company incurred a
significant increase in delinquent accounts, many of which occurred with
customers that no longer have active accounts with the Company. As a result, the
Company significantly increased its bad debt accrual throughout 1999.
The following is a summary of the allowance for doubtful accounts for the six
months ended June 30, 2000 and the year ended December 31, 1999:
June 30, December 31,
2000 1999
---------- ------------
Allowance for doubtful accounts, beginning
of year.......................................... $12,504 $ 836
Bad debt accrual................................... 1,636 11,496
Less: Write-off (adjustments) of uncollectible
Accounts......................................... 5,205 (172)
---------- ------------
Allowance for doubtful accounts, end of period .... $ 8,935 $12,504
========== ============
The Company continues to analyze its delinquent accounts resulting from the new
customer billing system implementation problems and expects to write off a
significant portion upon completion of its analysis. Based upon information
available at June 30, 2000, the Company believes the allowance for doubtful
accounts is adequate for potential uncollectible accounts.
16
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies (Continued)
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 certain sites. In addition, the Company has
periodically entered 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 such litigation can be estimated and
where an outcome is considered probable. The Company does not expect that any
known lawsuits, environmental costs and commitments will have a material adverse
effect on its financial condition or results of operations.
(7) New and Proposed Accounting Standards
Decommissioning: The Staff of the Securities and Exchange Commission ("SEC") has
questioned certain of the current accounting practices of the electric industry
regarding the recognition, measurement and classification of decommissioning
costs for nuclear generating stations in financial statements of electric
utilities. In February 2000, the Financial Accounting Standards Board ("FASB")
issued an exposure draft regarding Accounting for Obligations Associated with
the Retirement of Long-Lived Assets ("Exposure Draft"). The Exposure Draft
requires the recognition of a liability for an asset retirement obligation at
fair value. In addition, present value techniques used to calculate the
liability must use a credit adjusted risk-free rate. Subsequent remeasures of
the liability would be recognized using an allocation approach. The Company has
not yet determined the impact of the Exposure Draft.
EITF Issue 99-14, Recognition of Impairment Losses on Firmly Committed Executory
Contracts: The EITF has added an issue to its agenda to address impairment of
leased assets. A significant portion of the Company's nuclear generating assets
are held under operating leases. Based on the alternative accounting methods
being explored by the EITF, the related financial impact of the future adoption
of EITF Issue No. 99-14 should not have a material adverse effect on results of
operations. However, a complete evaluation of the financial impact from the
future adoption of EITF Issue No. 99-14 will be undeterminable until EITF
deliberations are completed and stranded cost recovery issues are resolved.
17
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(7) New and Proposed Accounting Standards (Continued)
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities, ("SFAS 133"): SFAS 133 establishes
accounting and reporting standards requiring derivative instruments to be
recorded in the balance sheet as either an asset or liability measured at its
fair value. SFAS 133 also requires that changes in the derivatives' fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met. Special accounting for qualifying hedges allows derivative gains and
losses to offset related results on the hedged item in the income statement, and
requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. In June 1999, FASB
issued SFAS 137 to amend the effective date for the compliance of SFAS 133 to
January 1, 2001. In June 2000, the FASB issued SFAS 138 that provides certain
amendments to SFAS 133. The amendments, among other things, expand the normal
sales and purchases exception to contracts that implicitly or explicitly permit
net settlement and contracts that have a market mechanism to facilitate net
settlement. The expanded exception excludes a significant portion of the
Company's contracts that previously would have required valuation under SFAS
133. The Company is in the process of reviewing and identifying all financial
instruments currently existing in the Company in compliance with the provisions
of SFAS 133 and SFAS 138. As a result of the SFAS 138 amendment to SFAS 133, the
Company does not believe that the impact of SFAS 133 will be material as most of
the Company's derivative instruments result in physical delivery or are
marked-to-market under EITF 98-10.
(8) Subsequent Events
Asset Acquisition and Related Agreements
The Company and Tri-State Generation and Transmission Association, Inc.
("Tri-State") entered into an asset sale agreement dated September 9, 1999,
pursuant to which Tri-State has agreed to sell to the Company certain assets to
be acquired by Tri-State as the result of Tri-State's merger with Plains
Electric Generation and Transmission Cooperative ("Plains") consisting primarily
of transmission assets, a fifty percent interest in an inactive power plant
located near Albuquerque, and an office building. The purchase price was
originally $13.2 million, subject to adjustment at the time of closing, with the
transaction to close in two phases. On July 1, 2000, the first phase was
completed, and the Company acquired the 50 percent ownership in the inactive
power plant and the office building. The second phase relating to the
transmission assets is expected to close by the end of 2000.
18
<PAGE>
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(8) Subsequent Events (Continued)
In addition, on July 1, 2000, the Company advanced $11.8 million to a former
Plains cooperative member as part of an agreement for the Company to become the
cooperative's power supplier. Approximately $4.3 million of this advance
represents an inducement for entering into a 10 year power sales agreement.
Accordingly, the Company will expense this amount in the third quarter as a
business development cost. The remaining $7.5 million will be repaid over 10
years. If the cooperative terminates the contract early, the whole $11.8 million
advance must be repaid to the Company.
Power Purchase Agreement
On October 4, 1996, the Company entered into a power purchase contract for the
rights to the output of a new gas-fired-generating plant located in Albuquerque,
NM. On July 13, 2000, the plant went into operation. The power purchase contract
provides the Company an additional 132 megawatts of electricity on demand to
help meet peak needs for twenty years with an option to renew the contract for
an additional five years. Under the terms of the contract, the Company will pay
a monthly capacity charge, which is subject to adjustment for inflation. The
energy purchase price under the contract is based on cost plus a margin.
Stock Repurchase
On August 8, 2000, the Company's Board of Directors approved a plan to
repurchase up to $35 million of the Company's common stock through the end of
the first quarter of 2001.
19
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is management's assessment of the Company's financial condition
and the significant factors affecting the results of operations. This discussion
should be read in conjunction with the Company's consolidated financial
statements and PART II, ITEM 1. - Legal Proceedings. Trends and contingencies of
a material nature are discussed to the extent known and considered relevant.
OVERVIEW
The Company is a public utility primarily engaged in the generation,
transmission, distribution and sale of electricity and in the transmission,
distribution and sale of natural gas within the State of New Mexico. In
addition, in pursuing new business opportunities, the Company provides energy
and utility-related activities through its wholly-owned subsidiary, Avistar,
Inc. ("Avistar").
UTILITY OPERATIONS
ELECTRIC BUSINESS UNIT
The Company provides jurisdictional retail electric service to a large area of
north central New Mexico, including the cities of Albuquerque and Santa Fe, and
certain other areas of New Mexico. As of June 30, 2000 and 1999 and December 31,
1999, approximately 366,000, 360,000 and 361,000, respectively, retail electric
customers were served by the Company.
The Company owns or leases 2,781 circuit miles of transmission lines,
interconnected east into Texas, west into Arizona, and north into Colorado and
Utah. Due to rapid load growth in recent years, most of the capacity on this
transmission system is fully committed and there is no additional access
available on a firm commitments basis. These factors, together with significant
physical constraints in the system, limit the ability to wheel power into the
Company's service area from outside the state.
NATURAL GAS BUSINESS UNIT
The Company's gas operations distribute natural gas to most of the major
communities in New Mexico, including Albuquerque and Santa Fe, serving
approximately 429,000, 422,000 and 426,000 customers as of June 30, 2000 and
1999 and December 31, 1999, respectively. The Company's customer base includes
both sales-service customers and transportation-service customers. Sales-service
customers purchase natural gas and receive transportation and delivery services
from the Company for which the Company receives both cost-of-gas and
cost-of-service revenues. Additionally, the Company makes occasional gas sales
to off-system customers. Off-system sales deliveries generally occur at
interstate pipeline interconnects with the Company's system.
Transportation-service customers, who procure gas independently of the Company
and contract with the Company for transportation and related services, are
billed cost-of-service revenues only.
20
<PAGE>
The Company obtains its supply of natural gas primarily from sources within New
Mexico pursuant to contracts with producers and marketers. These contracts are
generally sufficient to meet the Company's peak-day demand.
The following table shows gas revenues by customer class:
GAS REVENUES
(Thousands of dollars)
Three Months Ended Six Months Ended
June 30, June 30,
2000 1999 2000 1999
-------- -------- -------- --------
Retail .................. 30,551 30,504 93,639 85,297
Commercial .............. 8,238 7,234 24,931 23,917
Transportation*.......... 2,947 3,139 6,931 6,971
Other ................... 12,778 7,442 23,559 16,998
-------- -------- -------- --------
$ 54,514 $ 48,319 $149,960 $133,183
======== ======== ======== ========
The following table shows gas throughput by customer class:
GAS THROUGHPUT
(Thousands of decatherms)
Three Months Ended Six Months Ended
June 30, June 30,
2000 1999 2000 1999
------ ------ ------ ------
Retail ........... 3,689 4,386 14,920 18,695
Commercial ....... 1,519 1,612 5,155 6,366
Transportation* .. 10,663 10,547 19,674 18,386
Other ............ 3,075 1,889 4,962 4,332
------ ------ ------ ------
18,946 18,434 44,711 47,779
====== ====== ====== ======
*Customer-owned gas
GENERATION OPERATIONS
The Company's generation operations serve four principal markets. Sales to the
Company's utility operations to cover jurisdictional electric demand and sales
to firm-requirements wholesale customers, sometimes referred to collectively as
"system" sales, comprise two of these markets. Intercompany sales to the Utility
Operations are priced using internally developed transfer pricing and are not
21
<PAGE>
based on market rates. The third market consists of other contracted sales to
utilities for which the Generation Operations commits to deliver a specified
amount of capacity (measured in megawatts-MW) or energy (measured in megawatt
hours-MWh) over a given period of time. The fourth market consists of economy
energy sales made on an hourly basis at fluctuating, spot-market rates. Sales to
the third and fourth markets are sometimes referred to collectively as
"off-system" sales.
The following table shows electric revenues by customer class:
ELECTRIC REVENUES
(Thousands of dollars)
Three Months Ended Six Months Ended
June 30, June 30,
2000 1999 2000 1999
---------- --------- ---------- ---------
Jurisdictional sales................ $ 78,869 $ 79,197 $ 154,691 $ 157,168
Firm-requirement wholesale.......... 1,890 1,739 3,625 3,452
Other contracted off-system sales... 65,696 42,376 128,504 73,772
Economy energy sales................ 86,912 28,862 122,626 46,550
Other*.............................. (11,456) 2,960 (11,238) 3,646
---------- --------- ---------- ---------
$ 221,911 $ 155,134 $ 398,208 $ 284,588
========== ========= ========== =========
The following table shows electric sales by customer class:
ELECTRIC SALES BY MARKET
(Megawatt hours)
Three Months Ended Six Months Ended
June 30, June 30,
2000 1999 2000 1999
--------- --------- --------- -----------
Jurisdictional sales................ 1,721,661 1,660,189 3,376,811 3,260,199
Firm-requirement wholesale.......... 46,835 44,790 94,756 87,875
Other contracted off-system sales... 1,471,743 1,839,141 3,514,741 2,861,601
Other............................... 1,427,082 793,465 2,699,750 1,689,820
--------- --------- --------- -----------
4,667,321 4,337,585 9,686,058 7,899,495
========= ========= ========= ===========
* Includes mark-to-market gains/(losses). See footnote (4) in Notes to
Consolidated Financial Statements.
The Generation Operations has ownership interests in certain generating
facilities located in New Mexico, including Four Corners Power Plant, a coal
fired unit, and San Juan Generating Station, a coal fired unit. In addition, the
Company has ownership and leasehold interests in Palo Verde Nuclear Generating
Station ("PVNGS") located in Arizona. These generation assets are used to supply
retail and wholesale customers. The Generation Operations also owns Reeves
22
<PAGE>
Generating Station, a gas and oil fired unit and Las Vegas Generating Station, a
gas and oil fired unit that are used solely for reliability purposes or to
generate electricity for the wholesale market during peak demand periods in the
Generation Operations' wholesale power markets. As of June 30, 2000 and 1999 and
December 31, 1999, the total net generation capacity of facilities owned or
leased by the Generation Operations was 1,521 MW. On July 13, 2000, the Company
commenced a 20 year power purchase agreement for an additional 132 MW (see
footnote 8 to the Consolidated Financial Statements). In addition to generation
capacity, the Generation Operations purchases power in the open market. The
Generation Operations is also interconnected with various utilities for economy
interchanges and mutual assistance in emergencies. The Generation Operations has
been actively trading in the wholesale power market and has entered into and
anticipates that it will continue to enter into power purchase agreements to
accommodate its trading activity.
AVISTAR
The Company's wholly-owned subsidiary, Avistar, was formed in August 1999 as a
New Mexico corporation and is currently engaged in certain unregulated,
non-utility businesses, including energy and utility-related services previously
operated by the Company. The PRC authorized the Company to invest up to $50
million in equity in Avistar and to enter into a reciprocal loan agreement for
up to an additional $30 million. The Company has currently invested $25 million
in Avistar. In February 2000, Avistar invested $3 million in AMDAX.com, a
start-up company which plans to provide an on-line auction service to bring
together electricity buyers and sellers in the deregulated electric power
market.
RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY
Introduction of competitive market forces and restructuring of the electric
utility industry in New Mexico continue to be key issues facing the Company. New
Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring
Act") that was enacted into law in April 1999, begins to open the state's
electric power market to customer choice beginning in 2002. The Restructuring
Act gives schools, residential and small business customers the opportunity to
choose among competing power suppliers beginning in January 2002. Competition
will be expanded to include all customers starting in July 2002. Rural electric
cooperatives and municipal electric systems have the option not to participate
in the competitive market.
Residential and small business customers who do not select a power supplier in
the open market can buy their electricity through their local utility through a
"standard offer" whereby the local distribution utility will procure power
supplies through a process approved by the PRC. The local distribution utility
system and related services such as billing and metering will continue to be
regulated by the PRC, while transmission services and wholesale power sales will
remain subject to Federal regulation.
23
<PAGE>
The Restructuring Act does not require utilities to divest their generating
plants, but requires unregulated activities to be separated from the regulated
activities through creation of at least two separate corporations.
The law also provides for recovery of at least half of stranded costs. Recovery
of more than half is allowable if certain tests specified in the laws are met.
Stranded costs are defined in the law to include nuclear decommissioning costs,
regulatory assets, leases and other costs recognized under existing regulation.
Stranded costs will be recovered from customers over a five-year period.
Utilities will also be allowed to recover through 2007 all transition costs
reasonably incurred to comply with the new law (see "Stranded Costs" and
"Transition Costs" below). The PRC is authorized under the Restructuring Act to
extend this date by one year.
The Company plans to reorganize its operations by forming a holding company
structure as a means of achieving the corporate and asset separation required by
the Restructuring Act. The proposed holding company will be called Manzano
Corporation ("Manzano"). The Company's plan for a holding company structure will
separate the Company into two subsidiaries. Shareholders approved the holding
company structure and related share exchange in June 2000. If the Company
receives all necessary regulatory and other approvals, all of the Company's
electric and gas distribution and transmission assets and certain related
liabilities will be transferred to a newly created subsidiary. After this asset
transfer, this subsidiary will acquire the name "Public Service Company of New
Mexico" (for purposes of this discussion, the subsidiary will be referred to as
"UtilityCo") and the corporation formerly named Public Service Company of New
Mexico will be renamed Manzano Energy Corporation (for purposes of this
discussion, the subsidiary will be referred to as "Energy"). Energy will
continue to own the Company's existing electric generation and certain other
unregulated, competitive assets after completion of the transfer of the
regulated business to the newly created utility subsidiary. UtilityCo, Energy
and Avistar will be wholly-owned subsidiaries of Manzano.
The Company has filed its transition plan with the PRC pursuant to the
Restructuring Act in three parts. In November 1999, the Company filed the first
two parts of the transition plan with the PRC. Part one, which has been
approved, requested approval to create Manzano and UtilityCo as wholly-owned
shell subsidiaries of the Company. Part two of the Company's transition plan
requested that all PRC approvals necessary for the Company to implement the
formation of the holding company structure, the share exchange and the
separation plan. The part two hearing is currently scheduled for August 21,
2000. The balance of the schedule for the PRC proceeding has not yet been
established. Accordingly, the Company's management cannot predict when
implementation of the separation plan could occur. The PRC has ordered that
separation must occur by August 2001. On May 31, 2000, the Company filed with
the PRC part three of the transition plan requesting approval for the recovery
of stranded costs and other expenses associated with the transition to a
24
<PAGE>
competitive market, UtilityCo's rates for retail distribution services, the
procurement of power supplies for customers who do not select a power supplier
and other issues required to be considered under the Restructuring Act (see
"Other Issues Facing the Company - The Restructuring Act and the Formation of
Holding Company").
COMPETITIVE STRATEGY
The restructuring of the electric utility industry will provide new
opportunities; however, the Company anticipates that it will experience downward
pressure on the Company's earnings from their current levels. The reasons for
the downward pressure include possible limits on return on equity, the potential
disallowance of some stranded costs and the potential loss of certain customers
in a competitive environment.
Under a holding company structure, the regulated businesses (natural gas and
electric transmission and distribution) will be grouped under a separate company
and will focus on the core utility business in New Mexico. The unregulated
businesses under the Restructuring Act (power production, bulk power marketing
and energy services) will aggressively pursue efforts to expand energy marketing
and utility related businesses into carefully targeted markets in an effort to
increase shareholder value. The Company believes that successful operation of
its proposed unregulated business activities under a holding company structure
will better position the Company in an increasingly competitive utility
environment.
The Company's bulk power operations have contributed significant earnings to the
Company in recent years as a result of increased off-system sales. The Company
plans to expand its wholesale power trading functions which could include an
expansion of its generation portfolio. The Company continuously evaluates its
physical asset acquisition strategies to ensure an optimal mix of base-load
generation, peaking generation and purchased power in its power portfolio. In
addition to the continued power trading operations, the Company will further
focus on opportunities in the marketplace where excess capacity is disappearing
and mid- to long-term market demands are growing.
The Company's current business plan includes a 300% increase in sales and a
doubling of its generating capacity through the construction or acquisition of
additional power generation assets in its surrounding region of operations over
the next five to seven years. Such growth will be dependent upon the Company's
ability to generate $400 to $600 million to fund the Company's expansion. There
can be no assurance that these competitive businesses, particularly the
generation business, will be successful or, if unsuccessful, that they will not
have a direct or indirect adverse effect on the Company.
At the Federal level, there are a number of proposals on electric restructuring
being considered with no concrete timing for definitive actions. It is expected
that previously introduced restructuring bills will continue to be considered
this year. Issues such as stranded cost recovery, market power, utility
regulation reform, the role of states, subsidies, consumer protections and
environmental concerns are expected to be at the forefront of the Congressional
25
<PAGE>
debate. In addition, the FERC has stated that if Congress mandates electric
retail access, it should leave the details of the program to the states with the
FERC having the authority to order the necessary transmission access for the
delivery of power for the states' retail access programs.
Although it is unable to predict the ultimate outcome of retail competition in
New Mexico, the Company has been and will continue to be active at both the
state and Federal levels in the public policy debates on the restructuring of
the electric utility industry. The Company will continue to work with customers,
regulators, legislators and other interested parties to find solutions that
bring benefits from competition while recognizing the importance of reimbursing
utilities for past commitments.
26
<PAGE>
RESULTS OF OPERATIONS
The following discussion is based on the financial information presented in
Footnote 2 of the Consolidated Financial Statements. The table below sets forth
the operating results as percentages of total operating revenues for each
business segment.
<TABLE>
<CAPTION>
Three Months Ended June 30, 2000 Compared to Three Months Ended June 30, 1999
Three Months Ended June 30, 2000
Utility
------------------------------------
Electric Gas Generation
----------------- ----------------- ----------------
Operating revenues:
<S> <C> <C> <C> <C> <C> <C>
External customers.................... 130,142 99.86% 54,514 100.00% 143,042 64.46%
Intersegment revenues................. 177 0.14% - - 78,869 35.54%
------- -------- -------- ------- ------- -------
Total Revenues........................ 130,319 100.00% 54,514 100.00% 221,911 100.00%
------- -------- -------- ------- ------- -------
Cost of energy sold..................... 1,132 0.87% 30,097 55.21% 149,165 67.22%
Intercompany trans. price............... 78,869 60.52% 0.00% 177 0.08%
------- -------- -------- ------- ------- -------
Total fuel costs...................... 80,001 61.39% 30,097 55.21% 149,342 67.30%
------- -------- -------- ------- ------- -------
Gross Margin............................ 50,318 38.61% 24,417 44.79% 72,569 32.70%
------- -------- -------- ------- ------- -------
Administrative and other costs.......... 8,428 6.47% 9,393 17.23% 4,397 1.98%
Energy production costs................. 212 0.16% 421 0.77% 35,273 15.90%
Depreciation and amortization........... 7,953 6.10% 4,515 8.28% 10,159 4.58%
Transmission and distribution costs..... 8,002 6.14% 6,777 12.43% 16 0.01%
Taxes other than income taxes........... 3,165 2.43% 1,832 3.36% 2,567 1.16%
Income taxes............................ 7,094 5.44% (482) (0.88)% 3,488 1.57%
------- -------- -------- ------- ------- -------
Total non-fuel operating expenses..... 34,854 26.75% 22,456 41.19% 55,900 25.19%
------- -------- -------- ------- ------- -------
Operating income........................ $15,464 11.87% $ 1,961 3.60% $16,669 7.51%
------- -------- -------- ------- ------- -------
</TABLE>
<TABLE>
<CAPTION>
Three Months Ended June 30, 1999
Utility
------------------------------------
Electric Gas Generation
----------------- ----------------- ----------------
Operating revenues:
<S> <C> <C> <C> <C> <C> <C>
External customers..................... 136,927 99.87% 48,319 100.00% 75,937 48.95%
Intersegment revenues.................. 176 0.13% - 0.00% 79,197 51.05%
------- ------- -------- ------- -------- -------
Total revenues......................... 137,103 100.00% 48,319 100.00% 155,134 100.00%
------- ------- -------- ------- -------- -------
Cost of energy sold...................... 1,118 0.82% 20,423 42.27% 86,413 55.70%
Intercompany trans. price................ 79,197 57.76% - 0.00% 176 0.11%
------- ------- -------- ------- -------- -------
Total fuel costs....................... 80,315 58.58% 20,423 42.27% 86,589 55.82%
------- ------- -------- ------- -------- -------
Gross Margin............................. 56,788 41.42% 27,896 57.73% 68,545 44.18%
------- ------- -------- ------- -------- -------
Administrative and other costs........... 11,116 8.11% 11,270 23.32% 6,851 4.42%
Energy production costs.................. 653 0.48% 363 0.75% 34,191 22.04%
Depreciation and amortization............ 7,733 5.64% 4,722 9.77% 10,369 6.68%
Transmission and distribution costs...... 7,780 5.67% 7,444 15.41% 12 0.01%
Taxes other than income taxes............ 4,918 3.59% 1,675 3.47% 2,306 1.49%
Income taxes............................. 7,655 5.58% (177) (0.37)% 1,327 0.86%
------- ------- -------- ------- -------- -------
Total non-fuel operating expenses...... 39,855 29.07% 25,297 52.35% 55,056 35.49%
------- ------- -------- ------- -------- -------
Operating income......................... $16,933 12.35% $ 2,599 5.38% $ 13,489 8.70%
------- ------- -------- ------- -------- -------
</TABLE>
27
<PAGE>
UTILITY OPERATIONS
Electric Business Unit - Operating revenues declined $6.8 million (4.9%) for the
period to $130.3 million due to the implementation of the rate order in late
July 1999 (which lowered rates by $8.8 million quarter over quarter - see Other
Issues Facing the Company - Electric Rate Case). Lower rates were partially
offset by increased retail electricity delivery of 1.72 million MWh compared to
1.66 million MWh delivered last period, a 3.7% improvement.
The gross margin, or operating revenues minus cost of energy sold, decreased
$6.5 million reflecting a decrease in gross margin as a percentage of revenues
of 2.8%. This decline reflects the rate reduction discussed above. The Company's
generation operations exclusively provide power to the Company's electric
business unit. Intercompany purchases for the generation operations are priced
using internally developed transfer pricing and are not based on market rates.
Rates for electric service are based on a rate of return that includes certain
generation assets that are part of generation operations.
Administrative and general costs decreased $2.7 million (24.2%) for the period.
This decrease is due to reduced Year 2000 ("Y2K") compliance costs, reduced
costs related to implementing a customer billing system and lower associated bad
debt accruals. As a percentage of revenues, administrative and other decreased
to 6.5% from 8.1% for the period ended June 30, 2000 and 1999, respectively
primarily as a result of reduced costs.
Depreciation and amortization increased $0.2 million (2.8%) for the period. The
increase is due to the impact of amortizing the costs of a new customer billing
system. Depreciation and amortization as a percentage of revenues increased from
5.6% to 6.1% reflecting a slight increase in expense and the decrease in retail
energy revenues.
Transmission and distribution costs increased $0.2 million (2.9%) for the
quarter. As a percentage of revenues, transmission and distribution costs
increased from 5.7% to 6.1%. This increase was primarily the result of the
decrease in retail energy revenues.
Gas Business Unit - Operating revenues increased $6.2 million (12.8%) for the
period to $54.5 million. This increase was driven by a 10.2% increase in the
average rate charges per decatherm due to higher gas prices despite a warm
spring. Warmer than normal temperature resulted in a 2.8% volume decrease.
Residential and commercial volume decreased 13.2% while customers other than
residential and commercial volume increased 10.5%. This growth was primarily
attributed to industrial customers such as the Company's power generating
business whose demand increased due to the warm spring.
The gross margin, or operating revenues minus cost of energy sold, decreased
$3.5 million (12.5%). This decrease is due to lower volume.
28
<PAGE>
Administrative and general costs decreased $1.9 million (16.7%). This decrease
is mainly due to reduced Y2K compliance costs, customer billing system costs and
lower associated bad debt accruals.
Depreciation and amortization decreased $0.2 million (4.4%).
Transmission and distribution expenses decreased $0.7 million (9.0%) for the
period. The decrease is primarily due to reduced Y2K compliance costs.
GENERATION OPERATIONS
Operating revenues grew $66.8 million (43.0%) for the period to $221.9
million. This increase in wholesale electricity sales reflects strong regional
wholesale electric prices caused by an unseasonably warm spring, limited power
generation capacity due to various plant outages in the Western states and
increasing natural gas prices. These factors contributed to unusually high
wholesale prices which are expected to continue through the summer months but
which the Company does not believe to be sustainable in the long-term (see Other
Issues Facing the Company - Effects of Certain Events on Future Revenues). The
Company delivered wholesale (bulk) power of 2.95 million MWh of electricity this
period compared to 2.68 million MWh delivered last year, an increase of 10.0%.
Wholesale revenues to third-party customers increased from $75.9 million to
$143.0 million, an 88.4% increase. Wholesale sale revenues were negatively
impacted by the $13 million dollar unrealized mark-to-market loss the Company
recorded relating to its power trading contracts (see Note 4 of the Notes of the
Consolidated Financial Statements).
The gross margin, or operating revenues minus cost of energy sold, increased
$4.0 million (5.9%). However, gross margin as a percentage of revenues decreased
11.5%. This decline reflects higher fuel and purchased power costs due to higher
wholesale sales volumes and market prices.
Administrative and general costs decreased $2.5 million (35.8%) for the period.
This decrease is due to lower legal costs related to a lawsuit involving the
Company's decommissioning trust, and a PVNGS interruption and liability
insurance refund. As a percentage of revenues, administrative and other
decreased to 2.0% from 4.4% for the period ended June 30, 2000 and 1999,
respectively primarily as a result of reduced costs.
Energy production costs increased $1.1 million (3.2%) for the period. These
costs are generation related. The increase is due to higher maintenance costs of
$0.5 million primarily due to a scheduled outage at Four Corners Unit 4 in April
and May 2000 and higher San Juan operations costs of $0.6 million. As a
percentage of revenues, energy production costs decreased from 22.0% to 15.9%.
The decrease is primarily due to a significant increase in energy sales.
29
<PAGE>
UNREGULATED BUSINESSES
Avistar contributed $1.3 million in revenues for the period compared to $0.2
million in the comparable prior year period in accordance with its completed
contract revenue recognition policy as it received final acceptance on certain
contracts. Operating losses for Avistar decreased from $1.4 million in the prior
year to $0.5 million in the current year, primarily due to increased revenues.
CONSOLIDATED
Corporate administrative and general costs increased $5.0 million for the
period. This increase was due to higher legal costs, bonus accruals due to
increased earnings and other administrative costs, partially offset by reduced
Y2K compliance costs.
Other income and deductions, net of taxes, increased $0.4 million for the period
to $6.8 million due to net gains on certain corporate investments which include
the corporate hedge. In 1999, other income and deductions included a one-time
net gain of $1.2 million from closing down certain coal mine reclamation
activities.
Net interest charges decreased $1.0 million for the period to $16.4 million
primarily as a result of the retirement of $31.6 million of senior unsecured
notes in June and August 1999 and $32.8 million in January 2000.
The Company's consolidated income tax expense was $9.7 million, a decrease of
$0.6 million for the quarter. The Company's income tax effective rate decreased
from 36.2% to 35.1% due to the reversal of deferred income taxes accrued at
prior rates in accordance with ratemaking provisions.
The Company's net earnings from continuing operations for the quarter ended June
30, 2000, were $18.0 million compared to $16.9 million (excluding the one-time
gain of $1.2 million, net of taxes, related to mine closure activities) for the
quarter ended June 30, 1999, a 6.1% increase. Earnings per share from continuing
operations on a diluted basis were $0.45 compared to $0.41 (excluding the
one-time gain) for the quarter ended June 30, 2000 and 1999, respectively.
Diluted weighted average shares outstanding were 39.6 million and 40.9 million
in 2000 and 1999, respectively. The decrease reflects the common stock
repurchase program in 1999 and 2000. Despite the fact that 2000 results were
negatively impacted by the electric rate reduction and the mark-to-market loss
on the Company's power trading activities, net earnings per share from
continuing operations increased due to expansion of the Company's wholesale
electricity business and the common stock repurchase program.
30
<PAGE>
Six Months Ended June 30, 2000 Compared to Six Months Ended June 30, 1999
The table below sets forth the operating results as percentages of total
operating revenues for each business segment.
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
Utility
----------------------------------
Electric Gas Generation
---------------- ---------------- -----------------
Operating revenues:
<S> <C> <C> <C> <C> <C> <C>
External customers..................... 256,063 99.86% 149,060 100.00% 243,517 61.15%
Intersegment revenues.................. 353 0.14% - - 154,691 38.85%
------- ------- ------- ------- -------- -------
Total Revenues......................... 256,416 100.00% 149,060 100.00% 398,208 100.00%
------- ------- ------- ------- -------- -------
Cost of energy sold...................... 2,265 0.88% 87,930 58.99% 257,922 64.77%
Intercompany trans. price................ 154,691 60.33% - 0.00% 353 0.09%
------- ------- ------- ------- -------- -------
Total fuel costs....................... 156,956 61.21% 87,930 58.99% 258,275 64.86%
------- ------- ------- ------- -------- -------
Gross Margin............................. 99,460 38.79% 61,130 41.01% 139,933 35.14%
------- ------- ------- ------- -------- -------
Administrative and other costs........... 17,494 6.82% 19,306 12.95% 8,694 2.18%
Energy production costs.................. 628 0.24% 789 0.53% 70,131 17.61%
Depreciation and amortization............ 16,512 6.44% 9,881 6.63% 20,237 5.08%
Transmission and distribution costs...... 15,874 6.19% 14,178 9.51% 24 0.01%
Taxes other than income taxes............ 6,495 2.53% 3,808 2.55% 5,334 1.34%
Income taxes............................. 13,101 5.11% 3,089 2.07% 5,038 1.27%
------- ------- ------- ------- -------- -------
Total non-fuel operating expenses...... 70,104 27.34% 51,051 34.25% 109,458 27.49%
------- ------- ------- ------- -------- -------
Operating income......................... $29,356 11.45% $10,079 6.76% $ 30,475 7.65%
------- ------- ------- ------- -------- -------
</TABLE>
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
Utility
------------------------------------
Electric Gas Generation
----------------- ----------------- ---------------
Operating revenues:
<S> <C> <C> <C> <C> <C> <C>
External customers.................... 269,886 99.87% 133,183 100.00% 127,420 44.77%
Intersegment revenues................. 354 0.13% - 0.00% 157,168 55.23%
-------- ------- -------- ------- -------- -------
Total revenues........................ 270,240 100.00% 133,183 100.00% 284,588 100.00%
-------- ------- -------- ------- -------- -------
Cost of energy sold..................... 2,235 0.83% 68,680 51.57% 147,448 51.81%
Intercompany trans. Price............... 157,168 58.16% - 0.00% 354 0.12%
-------- ------- -------- ------- -------- -------
Total fuel costs...................... 159,403 58.99% 68,680 51.57% 147,802 51.94%
-------- ------- -------- ------- -------- -------
Gross Margin............................ 110,837 41.01% 64,503 48.43% 136,786 48.06%
-------- ------- -------- ------- -------- -------
Administrative and other costs.......... 21,940 8.12% 22,723 17.06% 14,324 5.03%
Energy production costs................. 1,171 0.43% 722 0.54% 67,508 23.72%
Depreciation and amortization........... 15,448 5.72% 9,404 7.06% 20,533 7.21%
Transmission and distribution costs..... 15,392 5.70% 14,100 10.59% 21 0.01%
Taxes other than income taxes........... 9,784 3.62% 3,298 2.48% 4,845 1.70%
Income taxes............................ 14,401 5.33% 3,329 2.50% 2,505 0.88%
-------- ------- -------- ------- -------- -------
Total non-fuel operating expenses..... 78,136 28.91% 53,576 40.23% 109,736 38.56%
-------- ------- -------- ------- -------- -------
Operating income........................ $ 32,701 12.10% $ 10,927 8.20% $ 27,050 9.50%
-------- ------- -------- ------- -------- -------
</TABLE>
31
<PAGE>
UTILITY OPERATIONS
Electric Business Unit - Operating revenues declined $13.8 million (5.1%) for
the period to $256.4 million due to the implementation of the rate order in late
July 1999 (which lowered rates by $18.5 million year-over-year) and unfavorable
price mix due to mild weather conditions, partially offset by increased retail
electricity delivery of 3.38 million MWh compared to 3.26 million MWh delivered
in the prior year period, a 3.6% improvement.
The gross margin, or operating revenues minus cost of energy sold, decreased
$11.4 million reflecting a decrease in gross margin as a percentage of revenues
of 2.2%. This decline reflects the rate reduction discussed above. The Company's
generation operations exclusively provide power to the Company's electric
business unit. Intercompany purchases for the generation operations are priced
using internally developed transfer pricing and are not based on market rates.
Rates for electric service are based on a rate of return that includes certain
generation assets that are part of generation operations.
Administrative and general costs decreased $4.4 million (20.3%) for the period.
This decrease is due to reduced Y2K compliance costs, customer billing system
costs and lower associated bad debt accruals. As a percentage of revenues,
administrative and other decreased to 6.8% from 8.1% for the six months ended
June 30, 2000 and 1999, respectively primarily as a result of reduced costs.
Depreciation and amortization increased $1.1 million (6.9%) for the period. The
increase is due to the impact of amortizing the costs of a new customer billing
system. Depreciation and amortization as a percentage of revenues increased from
5.7% to 6.4% reflecting an increase in expense and the decrease in retail energy
sales.
Transmission and distribution costs increased $0.5 million (3.1%) for the year.
As a percentage of revenues, transmission and distribution costs increased from
5.7% to 6.2%. This increase was primarily the result of the decrease in retail
energy sales.
Gas Business Unit - Operating revenues increased $15.9 million (11.9%) for the
period to $149.1 million. This increase was driven by a 19.4% increase in the
average rate charges per decatherm due to strong gas prices despite a mild
winter and warm spring, which resulted in a 6.4% volume decrease. Residential
and commercial customers volume decreased 19.9% while customers other than
residential and commercial volume increased 8.4%. This growth was primarily
attributed to industrial customers such as the Company's power generating
business whose demand increased due to the warm spring.
The gross margin, or operating revenues minus cost of energy sold, decreased
$3.4 million (5.2%). This decrease is due to lower volume.
32
<PAGE>
Administrative and general costs decreased $3.4 million (15.0%). This decrease
is mainly due to reduced Y2K compliance costs, customer billing system costs and
lower associated bad debt accruals.
GENERATION OPERATIONS
Operating revenues grew $113.6 million (39.9%) for the period to $398.2 million.
The Company delivered wholesale (bulk) power of 6.31 million MWh or electricity
this period compared to 4.64 million MWh delivered last year, an increase of
36.0% (see Results of Operations - Three Months Ended June 30, 2000 Compared to
Three Months Ended June 30, 1999 for a discussion of factors affecting results
in the second quarter of 2000).
The gross margin, or operating revenues minus cost of energy sold, decreased
$3.1 million reflecting a decrease in gross margin as a percentage of revenues
of 12.9%. This decline reflects higher fuel and purchased power costs due to
higher wholesale sales volumes and scheduled outages at the Company's San Juan
coal generation facility and Four Corners Plant.
Administrative and general costs decreased $5.6 million (39.3%) for the period.
This decrease is due to lower legal costs related to a lawsuit involving the
Company's decommissioning trust and a PVNGS interruption and liability insurance
refund. As a percentage of revenues, administrative and other decreased to 2.2%
from 5.0% for the six months ended June 30, 2000 and 1999, respectively
primarily as a result of reduced costs.
Energy production costs increased $2.6 million (3.9%) for the period. These
costs are generation related. The increase is due to higher maintenance costs of
$3.1 million due to scheduled outages at San Juan Unit 3 and Four Corners Unit
4, partially offset by lower operations expenses of $1.0 million due to lower
PVNGS employee costs as a result of additional employee incentive and retiree
healthcare costs in the prior year and additional PVNGS billings in 1999 for
1998 expenses. As a percentage of revenues, energy production costs decreased
from 23.7% to 17.6%. The decrease is primarily due to a significant increase in
energy sales and continued cost control.
UNREGULATED BUSINESSES
Avistar contributed $1.7 million in revenues for the period compared to $3.7
million in the comparable prior year period due to lower business volumes.
Operating losses for Avistar decreased from $1.9 million in the prior year to
$1.7 million in the current year.
33
<PAGE>
CONSOLIDATED
Corporate administrative and general costs increased $8.9 million for the
period. This increase was due to higher legal costs, bonus accruals due to
increased earnings and other administrative costs, partially offset by reduced
Y2K compliance costs.
Other income and deductions, net of taxes, increased $1.8 million for the period
to $14.3 million due to net gains on certain corporate investments which include
the corporate hedge. In 1999, other income and deductions included a one-time
net gain of $1.2 million from closing down certain coal mine reclamation
activities.
Net interest charges decreased $2.5 million for the period to $32.9 million
primarily as a result of the retirement of $31.6 million of senior unsecured
notes in June and August 1999 and $32.8 million in January 2000.
The Company's consolidated income tax expense, before the cumulative effect of
an accounting change, was $22.4 million, a decrease of $1.5 million for the
year. The Company's income tax effective rate, before the cumulative effect of
the accounting change, decreased from 36.6% to 35.9% due to the reversal of
deferred income taxes accrued at prior rates in accordance with ratemaking
provisions.
The Company's net earnings from continuing operations for the year-to-date
period ended June 30, 2000, were $39.9 million compared to $40.1 million
(excluding the one-time gain of $1.2 million, net of taxes, related to mine
closure activities) for the year-to-date period ended June 30, 1999. Earnings
per share from continuing operations excluding the cumulative effect of the
accounting change on a diluted basis were $1.00 compared to $0.96 (excluding the
one-time gain) for the year-to-date period ended June 30, 1999. Diluted weighted
average shares outstanding were 40.0 million and 41.4 million in 2000 and 1999,
respectively. The decrease reflects the common stock repurchase program in 1999
and 2000. Despite the fact that 2000 results were negatively impacted by the
electric rate reduction and the mark-to-market loss on the Company's power
trading activities, net earnings per share from continuing operations increased
due to expansion of the Company's wholesale electricity business and the common
stock repurchase program.
Cumulative Effect of a Change in Accounting Principle - Effective January 1,
1999, the Company adopted EITF Issue No. 98-10. The effect of the initial
application of the new standard is reported as a cumulative effect of a change
in accounting principle. As a result, the Company recorded additional earnings,
net of taxes, of approximately $3.5 million, or $0.09 per common share in 1999,
to recognize the gain on net open physical electricity purchase and sales
commitments considered to be trading activities.
34
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2000, the Company had working capital of $114.4 million including
cash and cash equivalents of $84.1 million. This is a decrease in working
capital of $45.8 million from December 31, 1999. This decrease is primarily the
result of a decrease in cash and cash equivalents of $36.3 million due to the
common stock and senior unsecured notes repurchases (see "Financing Activities"
and "Stock Repurchase" below) and the net liability of $13.8 million recorded
related to the mark-to-market valuation of the Company's energy trading
contracts and the reduction in income tax receivable due to the application of
prior year overpayments to the current year liability, partially offset by an
increase in accounts receivable (see discussion below).
Cash generated from operating activities was $96.9 million, an increase of
$9.2 million from 1999. This increase was primarily the result of the recovery
of purchased gas adjustments from utility customers, the decreased income tax
receivable, the collection of miscellaneous accounts receivable and the timing
of accounts payable payments, partially offset by an increase in accounts
receivable. Accounts receivable increased significantly as a result of increased
wholesale electricity sales and was partially offset by a decrease in utility
customer accounts receivable. This decrease in utility customer accounts
receivable is primarily a result of seasonal volume declines. The Company
continues to have a significant amount of delinquent accounts resulting from the
new customer billing system implementation in November 1998 (see Other Issues
Facing the Company - Implementation of New Billing System).
Cash used for investing activities was $65.0 million in the six months ended
June 30, 2000 compared to $5.8 million for the six months ended June 30, 1999.
This increased spending reflects $17.9 million relating to the acquisition of
transmission assets (see "Acquisition of Certain Assets and Related
Agreements"), plant improvements of $5 million at the Company's Reeves Power
Station, and the 1999 liquidation of insurance-based investments in the nuclear
decommissioning trust of $26.6 million (see financing activities for the payment
of decommissioning debt of $26.6 million for the six months ended June 30,
1999).
Cash used for financing activities was $68.2 million in the six months ended
June 30, 2000 compared to $82.5 million for the six months ended June 30, 1999.
This decrease is the result of $26.6 million of loan repayments associated with
nuclear decommissioning trust activities in 1999, partially offset by increased
senior unsecured notes repurchases at a cost of $32.8 million in 2000 compared
to $21.1 million in 1999.
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 generating systems, upgrading and expanding the electric and gas
35
<PAGE>
transmission and distribution systems and purchasing nuclear fuel. Projections
for total capital requirements and construction expenditures for 2000 are $250.9
million and $219.1 million, respectively. Such projections for the years 2000
through 2004 are $1.2 billion and $1.1 billion, respectively. These estimates
are under continuing review and subject to on-going adjustment (see Competitive
Strategy above).
The Company's construction expenditures for the six months ended June 30, 2000
were entirely funded through cash generated from operations. The Company
currently anticipates that internal cash generation and current debt capacity
will be sufficient to meet capital requirements for the years 2000 through 2004
assuming the Company receives a reasonable recovery of its stranded costs (see
"Stranded Costs" below). To cover the difference in the amounts and timing of
cash generation and cash requirements, the Company intends to use short-term
borrowings under its liquidity arrangements.
Liquidity
At August 1, 2000, the Company had $175 million of available liquidity
arrangements, consisting of $150 million from a senior unsecured revolving
credit facility ("Credit Facility"), and $25 million in local lines of credit.
The Credit Facility will expire in March 2003. There were no outstanding
borrowings as of August 1, 2000.
The Company's ability to finance its construction program at a reasonable cost
and to provide for other capital needs is largely dependent upon its ability to
earn a fair return on equity, results of operations, credit ratings, regulatory
approvals and financial market conditions. Financing flexibility is enhanced by
providing a high percentage of total capital requirements from internal sources
and having the ability, if necessary, to issue long-term securities, and to
obtain short-term credit.
The Company's rating outlook by Standard and Poor's ("S&P") is described as
"stable". S&P has rated the Company's senior unsecured debt and bank loan credit
"BBB-". The Company's rating outlook by Moody's Investors Services, Inc
("Moody's") is "developing". Moody's has rated the Company's senior unsecured
notes and senior unsecured pollution control revenue bonds "Baa3"; and preferred
stock "ba1". The EIP lease obligation is also rated "Ba1". Duff & Phelps Credit
Rating Co. ("DCR") rates the Company' senior unsecured notes and senior
unsecured pollution control revenue bonds "BBB-", the Company's EIP lease
obligation "BB+" and the Company's preferred stock "BB-". Investors are
cautioned that a security rating is not a recommendation to buy, sell or hold
securities, that it may be subject to revision or withdrawal at any time by the
assigning rating organization, and that each rating should be evaluated
independently of any other rating.
Future rating actions for the Company's securities will depend in large part on
the actions of the PRC relating to numerous restructuring issues, including the
36
<PAGE>
Company's proposed plan to separate the utility into a generation business and a
distribution and transmission business as required by the Restructuring Act
("Proposed Plan"). The Company believes that based on its Proposed Plan (see
"Proposed Holding Company Plan" below), that UtilityCo and PowerCo will both
receive investment grade credit ratings, however, such ratings will be
contingent upon many factors that have yet to be determined. DCR announced that
assuming the Company implements its Proposed Plan, it would expect to issue
investment grade ratings for UtilityCo, and PowerCo's rating would "border
investment grade". DCR cautioned that ratings for UtilityCo and PowerCo were
highly conditional upon reaching assumptions provided by the Company.
Covenants in the Company's Palo Verde Nuclear Generating Station Units 1 and 2
lease agreements limit the Company's ability, without consent of the owner
participants in the lease transactions: (i) to enter into any merger or
consolidation, or (ii) except in connection with normal dividend policy, to
convey, transfer, lease or dividend more than 5% of its assets in any single
transaction or series of related transactions. The Credit Facility imposes
similar restrictions regardless of credit ratings.
Financing Activities
In January 2000, the Company reacquired $34.7 million of its 7.5% senior
unsecured notes through open market purchases at a cost of $32.8 million. On
October 28, 1999, tax-exempt pollution control revenue bonds of $11.5 million
with an interest rate of 6.60% were issued to partially reimburse the Company
for expenditures associated with its share of a recently completed upgrade of
the emission control system at SJGS.
The Company currently has no requirements for long-term financings during the
period of 2000 through 2004 except as part of its Proposed Plan (see "Proposed
Holding Company Plan" below). However, during this period, the Company could
enter into long-term financings for the purpose of strengthening its balance
sheet and reducing its cost of capital. The Company continues to evaluate its
investment and debt retirement options to optimize its financing strategy and
earnings potential. No additional first mortgage bonds may be issued under the
Company's mortgage. The amount of SUNs that may be issued is not limited by the
SUNs indenture. However, debt to capital requirements in certain of the
Company's financial instruments would ultimately restrict the Company's ability
to issue SUNs.
Proposed Holding Company Plan
On April 18, 2000, the Company filed as an exhibit on Form 8-K, unaudited pro
forma financial statements of PowerCo and UtilityCo that give effect to the
Company's Proposed Plan. The Proposed Plan was part of the Company's part three
filing with the PRC. The Proposed Plan is subject to regulatory and other
37
<PAGE>
approvals as well as market, economic and business conditions. As such, the
Proposed Plan may be subject to significant changes before implementation and
the pro forma financial statements as filed in the Form 8-K may require revision
to reflect the final plan of separation pursuant to the Restructuring Act.
The Proposed Plan assumes that the Asset Transfer will be accomplished as
follows: Manzano will make an equity contribution to UtilityCo of $425 million
of regulated assets. These assets will be transferred through a dividend from
PowerCo to Manzano. UtilityCo will then acquire the remaining regulated assets
from PowerCo through the following transactions: (i) by way of an exchange
offer, as described below, an assumption of PowerCo's (formerly the Company's)
outstanding public Senior Unsecured Notes ("SUNs") and preferred stock, (ii) the
proceeds (approximately $253 million) from the issuance of commercial paper and
newly-issued UtilityCo SUNs, and (iii) the assumption of $334 million of certain
related liabilities. All transactions are expected to be completed
simultaneously.
The current holders of PowerCo's public SUNs will be offered the opportunity to
exchange their approximately $368 million of existing SUNs for $368 million of
SUNs issued by UtilityCo with like terms and conditions. The current holders of
PowerCo's preferred stock will be offered the opportunity to exchange their
approximately $12.8 million of preferred stock for preferred stock issued by
UtilityCo with like terms and conditions.
Although there are other alternatives to finance the acquisition of the
regulated assets from PowerCo, based on current market, economic and business
conditions, the Company currently believes that the foregoing transactions
represent the most advantageous way to effect the Asset Transfer. However, the
structure of Proposed Plan is subject to change as the regulatory approval
process continues and is ultimately resolved.
Stock Repurchase
In March 1999, the Company's board of directors approved a plan to repurchase up
to 1,587,000 shares of the Company's outstanding common stock with maximum
purchase price of $19.00 per share. In December 1999, the Company's board of
directors authorized the Company to repurchase up to an additional $20.0 million
of the Company's common stock. As of December 31, 1999, the Company repurchased
1,070,700 shares of its previously outstanding common stock at a cost of $18.8
million. From January 2, 2000 through March 31, 2000, the Company repurchased an
additional 1,167,684 shares of its outstanding common stock at a cost of $18.9
million. The Company has repurchased all shares authorized in March 1999 and
December 1999 by the Board of Directors.
On August 8, 2000, the Company's Board of Directors approved a plan to
repurchase up to $35 million of the Company's common stock through the end of
the first quarter of 2001.
38
<PAGE>
Acquisition of Certain Assets and Related Agreements
The Company and Tri-State Generation and Transmission Association, Inc.
("Tri-State") entered into an asset sale agreement dated September 9, 1999,
pursuant to which Tri-State has agreed to sell to the Company certain assets to
be acquired by Tri-State as the result of Tri-State's merger with Plains
Electric Generation and Transmission Cooperative ("Plains") consisting primarily
of transmission assets, a fifty percent interest in an inactive power plant
located near Albuquerque, and an office building. The purchase price was
originally $13.2 million, subject to adjustment at the time of closing, with the
transaction to close in two phases. On July 1, 2000, the first phase was
completed, and the Company acquired the 50 percent ownership in the inactive
power plant and the office building. The second phase relating to the
transmission assets is expected to close by the end of 2000.
In addition, on July 1, 2000, the Company advanced $11.8 million to a former
Plains cooperative member as part of an agreement for the Company to become the
cooperative's power supplier. Approximately $4.3 million of this advance
represents an inducement for entering into a 10 year power sales agreement.
Accordingly, the Company will expense this amount in the third quarter as a
business development cost. The remaining $7.5 million will be repaid over 10
years. If the cooperative terminates the contract early, the whole $11.8 million
advance must be repaid to the Company.
Dividends
The Company's board of directors reviews the Company's dividend policy on a
continuing basis. The declaration of common dividends is dependent upon a number
of factors including the extent to which cash flows will support dividends, the
availability of retained earnings, the financial circumstances and performance
of the Company, the PRC's decisions on the Company's various regulatory cases
currently pending, the effect of deregulating generation markets and market
economic conditions generally. In addition, the ability to recover stranded
costs in deregulation, future growth plans and the related capital requirements
and standard business considerations will also affect the Company's ability to
pay dividends. In addition, following the separation as required by the
Restructuring Act, the ability of the proposed holding company, Manzano, to pay
dividends will depend initially on the dividends and other distributions that
UtilityCo and PowerCo pay to the holding company.
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Capital Structure
The Company's capitalization, including current maturities of long-term debt is
shown below:
June 30, December 31,
2000 1999
-------- ------------
Common Equity.............................. 48.3% 47.3%
Preferred Stock............................ 0.7 0.7
Long-term Debt............................. 51.0 52.0
----- -----
Total Capitalization*................... 100.0% 100.0%
===== =====
* Total capitalization does not include as debt the present value ($139
million as of June 30, 2000 and $147 million as of December 31, 999) of
the Company's lease obligations for PVNGS Units 1 and 2 and EIP.
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OTHER ISSUES FACING THE COMPANY
THE RESTRUCTURING ACT AND THE Formation of Holding Company
The Restructuring Act requires that assets and activities subject to the PRC
jurisdiction, primarily electric and gas distribution, and transmission assets
and activities (collectively, the "Regulated Business"), be separated from
competitive businesses, primarily electric generation and service and certain
other energy services (collectively, the "Deregulated Competitive Businesses").
Such separation is required to be accomplished through the creation of at least
two separate corporations. The Company has decided to accomplish the mandated
separation by the formation of a holding company and the transfer of the
Regulated Businesses to a newly-created, wholly-owned subsidiary of the holding
company, subject to various approvals. The holding company structure is
expressly authorized by the Restructuring Act. Corporate separation of the
Regulated Business from the Deregulated Competitive Businesses must be completed
by August 1, 2001. Completion of corporate separation will require a number of
regulatory approvals by, among others, the PRC, the Federal Energy Regulatory
Commission, Nuclear Regulatory Commission and the Securities and Exchange
Commission.
In June 2000, shareholders approved the separation and related share exchange;
however, completion of corporate separation will also require certain other
consents. Completion may also entail significant restructuring activities with
respect to the Company's existing liquidity arrangements and the Company's
publicly-held senior unsecured notes of which $368 million were outstanding as
of June 30, 2000. Holders of the Company's senior unsecured notes, $100 million
at 7.5% and $268.4 million at 7.1%, may be offered the opportunity to exchange
their securities for similar senior unsecured notes of the newly created
regulated business (see "Liquidity and Capital Resources - Financing Activities
and Proposed Holding Company Plan" above).
Stranded Costs
The Restructuring Act recognizes that electric utilities should be permitted a
reasonable opportunity to recover an appropriate amount of the costs previously
incurred in providing electric service to their customers ("stranded costs").
Stranded costs represent all costs associated with generation related assets,
currently in rates, in excess of the expected competitive market price 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
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residential or small business customers during the transition period. The
Restructuring Act also allows for the recovery of nuclear decommissioning costs
by means of a separate wires charge over the life of the underlying generation
assets (see NRC Prefunding below).
Approximately $99 million of costs associated with the Deregulated Competitive
Business were established as regulatory assets. The Company expects to recover
these regulatory assets along with other stranded costs associated with the
Deregulated Competitive Business through its stranded costs recovery. As a
result, these regulatory assets continue to be classified as regulatory assets,
although the Company has discontinued Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71) and adopted Statement of Financial Accounting Standards No. 101,
"Regulated Enterprises--Accounting for the Discontinuance of Application of FASB
Statement 71." Stranded costs include other operating costs in excess of the
established regulatory assets. On May 31, 2000, the Company filed with the PRC
its proposal to recover its stranded costs. These costs, excluding nuclear
decommissioning costs, total a present value of $691.6 million. In addition,
stranded costs associated with decommissioning the Company's portion of the Palo
Verde nuclear plant total an additional present value of $44.4 million. This
amount considers the effect of expected earnings on PNM's qualified nuclear
decommissioning trusts.
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 Company believes that the
Restructuring Act if properly applied provides an opportunity for recovery of a
reasonable amount of stranded costs. If regulatory orders do not provide for a
reasonable recovery, the Company is prepared to vigorously pursue judicial
remedies. Final determination and quantification of stranded cost recovery has
not been made by the PRC. The determination will 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 authorizes utilities to recover in full any
prudent and reasonable costs incurred in implementing full open access
("transition costs"). These transition costs will be recovered through 2007 by
means of a separate wires charge. The PRC may extend this date by up to one
year. The Company is still evaluating its expected transition costs and has not
made a final determination of those costs. The Company, however, currently
estimates that these costs will be approximately $46 million, including
allowances for certain costs which are non-deductible for income tax purposes.
Transition costs for which the Company will seek recovery include professional
fees, financing costs including underwriting fees, consents relating to the
transfer of assets, management information system changes including billing
system changes and public and customer education and communications. Recoverable
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transition costs are currently being capitalized and will be amortized over the
recovery period to match related revenues. Recovery of any transition costs
which are not deemed recoverable by the PRC may be vigorously pursued through
all remedies available to the Company with the ultimate outcome uncertain. Costs
not recoverable will be expensed when incurred unless these costs are otherwise
permitted to be capitalized under current and future accounting rules. If the
amount of non-recoverable transition costs is material, the resulting charge to
earnings may have a material effect on the future financial results and position
of the Company.
Deregulated Competitive Businesses
The Deregulated Competitive Businesses which would be retained by the Company
include the Company's interests in generation facilities, including PVNGS, Four
Corners, and SJGS, together with the pollution control facilities which have
been financed with pollution control revenue bonds. Based on the Proposed Plan,
approximately $586 million in pollution control revenue bonds would remain as
obligations of the generation subsidiary, as would certain other of the
Company's long-term obligations. The Deregulated Competitive Businesses would
not be subject to regulation by the PRC.
The Company will continue its Deregulated Competitive Business following the
restructuring, which will be subject to market conditions. Following the
separation as required by the Restructuring Act, in support of its wholesale
trading operations, the Company is targeting to double its generating capacity
and triple its sales volume. Avistar, the Company's current non-regulated
subsidiary, provides services in the areas of utility management for
municipalities and other communities, remote metering and development of energy
conservation and supply projects for federal government facilities. The Company
does not anticipate an earnings contribution from Avistar over the next few
years.
NRC Prefunding
Pursuant to NRC rules on financial assurance requirements for the
decommissioning of nuclear power plant, the Company has a program for funding
its share of decommissioning costs for PVNGS through a sinking fund mechanism
(see "PVNGS Decommissioning Funding"). The NRC rules on financial assurance
became effective on November 23, 1998. The amended rules provide that a licensee
may use an external sinking fund as the exclusive financial assurance mechanism
if the licensee recovers estimated decommissioning costs through cost of service
rates or a "non-bypassable charge". Other mechanisms are prescribed, such as
prepayment, surety methods, insurance and other guarantees, to the extent that
the requirements for exclusive reliance on the fund mechanism are not met.
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The Restructuring Act allows for the recoverability of 50% up to 100% of
stranded costs including nuclear decommissioning costs (see "Stranded Costs").
The Restructuring Act 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 states that it is not requiring 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. 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.
In addition, as part of the determination and quantification of the stranded
costs related to the decommissioning, the Company estimated its future
decommissioning costs. If the Company's estimate proves to be less than the
actual costs of decommissioning, any cost in excess of the amount allowed
through stranded cost recovery may not be recoverable. Such excess costs, if
any, will also be subject to the pre-funding requirements discussed above.
Competition
Under current law, the Company is not in direct retail competition with any
other regulated electric and gas utility. Nevertheless, the Company is subject
to varying degrees of competition in certain territories adjacent to or within
areas it serves that are also currently served by other utilities in its region
as well as cooperatives, municipalities, electric districts and similar types of
government organizations.
The Restructuring Act opens the state's electric power market to customer choice
for certain customers beginning in January 2002 and the balance of customers by
July 2002. As a result, the Company may face competition from companies with
greater financial and other resources. There can be no assurance that the
Company will not face competition in the future that would adversely affect its
results.
It is the current intention to have the Company's Deregulated Competitive
Businesses engage primarily in energy-related businesses that will not be
regulated by state or Federal agencies that currently regulate public utilities
(other than the FERC and NRC). These competitive businesses, including the
generation business, will encounter competition and other factors not previously
experienced by the Company, and may have different, and perhaps greater,
investment risks than those involved in the regulated business that will be
engaged in by the Regulated Businesses. Specifically, the passage of the
Restructuring Act and deregulation in the electric utility industry generally
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are likely to have an impact on the price and margins for electric generation
and thus, the return on the investment in electric generation assets. In
response to competition and the need to gain economies of scale, electricity
producers will need to control costs to maintain margins, profitability and cash
flow that will be adequate to support investments in new technology and
infrastructure. The Company will have to compete directly with independent power
producers, many of whom will be larger in scale, thus creating a competitive
advantage for those producers due to scale efficiencies. The Company's current
business plan includes a 300% increase in sales achieved by doubling power
generation assets in its surrounding region of operations through construction
or acquisition over the next five to seven years. Such growth will be dependent
upon the Company's ability to generate $400 to $600 million to fund the
deregulated competitive expansion. There can be no assurance that these
Deregulated Competitive Businesses, particularly the generation business, will
be successful or, if unsuccessful, that they will not have a direct or indirect
adverse effect on the Company.
Implementation of New Billing System
On November 30, 1998, the Company implemented a new customer billing system. Due
to a significant number of problems associated with the implementation of the
new billing system, the Company was unable to generate appropriate bills for all
its customers through the first quarter of 1999 and was unable to analyze
delinquent accounts until November 1999.
As a result of the delay of normal collection activities, the Company incurred a
significant increase in delinquent accounts, many of which occurred with
customers that no longer have active accounts with the Company. As a result, the
Company significantly increased its bad debt accrual throughout 1999.
The following is a summary of the allowance for doubtful accounts during for the
three months ended June 30, 2000 and year ended December 31, 1999:
June 30, December 31,
2000 1999
--------- -----------
(In thousands)
Allowance for doubtful accounts, beginning
of year........................................... $ 12,504 $ 836
Bad debt accrual.................................... 1,636 11,496
Less: Write off (adjustments) of uncollectible
accounts.......................................... 5,205 (172)
--------- -----------
Allowance for doubtful accounts, end of period ..... $ 8,935 $ 12,504
========= ===========
The Company is still analyzing its delinquent accounts resulting from the new
customer billing system implementation problems and expects to write off a
significant portion upon completion of its analysis. Based upon information
available at June 30, 2000, the Company believes the allowance for doubtful
accounts is adequate for management's estimate of potential uncollectible
accounts.
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Electric Rate Case
On August 25, 1999, the PRC issued an order approving settlement of the
Company's electric rate case. The PRC ordered the Company to reduce its electric
rates by $34.0 million retroactive to July 30, 1999. In addition, the order
includes a rate freeze until retail electric competition is fully implemented in
New Mexico or until January 1, 2003. The settlement reduces annual revenues by
an estimated $37.0 million based on expected customer growth and will reduce
electric distribution operating revenues in the year 2000 by approximately $20
million.
As part of the settlement, the Company agreed that certain changes to the
language of the retail tariff under which Kirtland Air Force Base ("KAFB")
currently takes service be considered in a separate proceeding before the PRC.
Hearings on this issue have not yet been scheduled. KAFB has not renewed its
power service contract with the Company that expired in December 1999 but
continues to purchase retail service from the Company.
GAS RATE ORDERS
In April 2000, the New Mexico Supreme Court ("Supreme Court") ruled in favor of
the Company in overturning a $6.9 million rate reduction imposed on the
Company's natural gas utility by the state's former Public Utility Commission
("PUC") in 1997 for its 1995 gas rate case. Although the Supreme Court upheld
certain portions of the gas rate case order by the PUC, the Supreme Court
vacated the rate order as "unreasonable and unlawful" because certain
disallowances ordered by the PUC unreasonably hindered the Company's ability to
earn a fair rate of return. The case has been remanded to the PRC. The Company
has $19.4 million of reserves at June 30, 2000 related to regulatory assets
associated with the rate case order. The Supreme Court order has supported
recovery of many of the costs that the Company has included in these reserves.
In addition in March 2000, the Supreme Court vacated the PUC's final order in
the Company's 1997 gas rate case and remanded it back to the PRC. The Supreme
Court specifically rejected portions of the final order requiring the Company to
offer residential customers a choice of utility access fees.
The Company has negotiated a stipulated settlement agreement with the PRC staff
which must be approved by the PRC. The settlement would resolve all issues
raised by the Supreme Court's remand through a global settlement. If approved by
the PRC, the settlement would add about $1.2 million to PNM revenues in the
final quarter of 2000, $4.7 million in 2001, and $3.9 million in 2002. Upon
approval, PNM will reverse certain reserves to costs recovered in the settlement
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that were recorded against earnings at the time of the original regulatory
orders, resulting in a one-time gain of $5.4 million. That amount will be
collected from customers in rates over the next 13 years. Hearings on the
proposed settlement are scheduled to begin August 14. The PRC has said it
expects to issue a final decision on the two gas rate cases by the end of
September.
POWER OUTAGE
On March 18, 2000, a power outage, caused by a brush fire which affected three
main transmission lines, resulted in a loss of power for a significant portion
of the state of New Mexico. The fire was caused by circumstances outside the
control of the Company. The power outage caused brownouts and ultimately
blacked-out several major communities in the state for up to four hours. The
damage to the Company's transmission lines and the interruption to business
caused by the fire were not material. The Company has received approximately
1,500 claims for property damage, mainly for small appliances, resulting from
the power outage. No lawsuits against the Company have been filed related to
this event. The Company has informed claimants that it will not reimburse them
for damage on the basis that the Company was not at fault.
EFFECTS OF CERTAIN EVENTS ON FUTURE REVENUES
Subsequent to June 30, 2000, due to the unusually high price levels experienced
in the spring and early summer of this year, the California ISO Board imposed a
price cap of $250 per MWh for real time purchases. During the second quarter,
regional wholesale electricity prices reached $750 per MWh. In addition to sales
to the California PX and ISO markets, the Company sells power to customers in
other jurisdictions whose prices are influenced by the California ISO caps.
Approximately $28.6 million of wholesale revenues for the three months ended
June 30, 2000 represent amounts earned in excess of $250 per MWh on sales to all
customers. Price controls, such as those imposed in California, could have a
material adverse effect on the Generation Operations' revenue growth.
The Company's 100 MW power sale contract with San Diego Gas and Electric Company
("SDG&E") will expire in April of 2001. SDG&E has notified the Company that it
will not renew this contract. The Company currently estimates that the net
revenue reduction resulting from the expiration of the SDG&E contract will be
approximately $20 million annually. In addition, previously reported litigation
between the Company and SDG&E regarding prior years' contract pricing has been
resolved in the Company's favor.
On October 4, 1999, Western Area Power Administration ("Western") filed a
petition at the FERC requesting the FERC, on an expedited basis, to order the
Company to provide network transmission service to Western under the Company's
Open Access Transmission Tariff on behalf of the United States Department of
Energy ("DOE") as contracting agent for KAFB. The Company is opposing the
Western petition and intends to litigate this matter vigorously. The net revenue
reduction to the Company if the DOE replaces the Company as the power supplier
to KAFB is estimated to be approximately $7.0 million annually.
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A further discussion of these and other legal proceedings can be found in PART
II, ITEM 1. - "LEGAL PROCEEDINGS" in this Form 10-Q.
COAL FUEL SUPPLY
The coal requirements for the SJGS are being supplied by SJCC, a wholly-owned
subsidiary of BHP, from certain Federal, state and private coal leases under a
Coal Sales Agreement, pursuant to which SJCC will supply processed coal for
operation of the SJGS until 2017. The primary sources of coal for current
operations are a mine adjacent to the SJGS and a mine located approximately 25
miles northeast of the SJGS in the La Plata area of northwestern New Mexico.
Additional coal resources will be required. The Company is currently in
discussions regarding alternatives.
In 1997, the Company was notified by SJCC of certain audit exceptions identified
by the Federal Minerals Management Service ("MMS") for the period 1986 through
1997. These exceptions pertain to the valuation of coal for purposes of
calculating the Federal coal royalty. Primary issues include whether coal
processing and transportation costs should be included in the base value of La
Plata coal for royalty determination. Administrative appeals of the MMS claims
are pending.
The Company was notified during the fourth quarter of 1998 that the MMS agreed
to a mediation of the claims. It is the Company's understanding that the
mediation has not yet occurred. The Company is unable to predict the outcome of
this matter and the Company's exposures have not yet been assessed.
In 1996, the Company was notified by SJCC that the Navajo Nation proposed to
select certain properties within the San Juan and La Plata Mines (the "mining
properties") pursuant to the Navajo-Hopi Land Settlement Act of 1974 (the
"Act"). The mining properties are operated by SJCC under leases from the BLM and
comprise a portion of the fuel supply for the SJGS. An administrative appeal by
SJCC is pending. In the appeal, SJCC argued that transfer of the mining
properties to the Navajo Nation may subject the mining operations to taxation
and additional regulation by the Navajo Nation, both of which could increase the
price of coal that might potentially be passed on to the SJGS through the
existing coal sales agreement. The Company is monitoring the appeal and other
developments on this issue and will continue to assess potential impacts to the
SJGS and the Company's operations. The Company is unable to predict the ultimate
outcome of this matter.
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FUEL, WATER AND GAS NECESSARY FOR GENERATION OF ELECTRICITY
The Company's generation mix for 1999 was 67.6% coal, 31.0% nuclear and 1.4% gas
and oil. Due to locally available natural gas and oil supplies, the utilization
of locally available coal deposits and the generally abundant supply of nuclear
fuel, the Company believes that adequate sources of fuel are available for its
generating stations (see "Coal Fuel Supply" above).
Water for Four Corners and SJGS is obtained from the San Juan River. BHP holds
rights to San Juan River water and has committed a portion of such rights to
Four Corners through the life of the project. The Company and Tucson have a
contract with the USBR for consumption of 16,200 acre feet of water per year for
the SJGS, which contract expires in 2005. In addition, the Company was granted
the authority to consume 8,000 acre feet of water per year under a state permit
that is held by BHP. The Company is of the opinion that sufficient water is
under contract for the SJGS through 2005. The Company has signed a contract with
the Jicarilla Apache Tribe for a twenty-seven year term, beginning in 2006, for
replacement of the current USBR contract for 16,200 AF of water. The contract
must still be approved by the USBR and is also subject to environmental
approvals. The Company is actively involved in the San Juan River Recovery
Implementation Program to mitigate any concerns with the taking of the
negotiated water supply from a river that contains endangered species and
critical habitat. The Company believes that it will continue to have adequate
sources of water available for its generating stations.
The Company obtains its supply of natural gas primarily from sources within New
Mexico pursuant to contracts with producers and marketers. These contracts are
generally sufficient to meet the Company's peak-day demand. The Company serves
certain cities which depend on EPNG or Transwestern Pipeline Company for
transportation of gas supplies. Because these cities are not directly connected
to the Company's transmission facilities, gas transported by these companies is
the sole supply source for those cities. The Company believes that adequate
sources of gas are available for its distribution systems.
NEW SOURCE REVIEW RULES
The United States Environmental Protection Agency ("EPA") has proposed changes
to its New Source Review (NSR) rules that could result in many actions at power
plants that have previously been considered routine repair and maintenance
activities (and hence not subject to the application of NSR requirements) as now
being subject to NSR. The EPA has held stakeholder meetings to obtain the
perspective of the various stakeholders (including the electric utility
industry, regulatory agencies and environmental groups) on changes to the NSR
rules.
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In November 1999, the Department of Justice at the request of the EPA filed
complaints against seven companies alleging the companies over the past 25 years
had made modifications to their plants in violation of the NSR requirements, and
in some cases the New Source Performance Standards (NSPS) regulations. Whether
or not the EPA will prevail is unclear at this time. The EPA has reached a
settlement with one of the companies sued by the Justice Department. 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.
The nature and cost of the impacts of EPA's changed interpretation of the
application of the NSR and NSPS, together with proposed changes to these
regulations, may be significant to the power production industry. However, the
Company cannot quantify these impacts with regard to its power plants. If the
EPA should prevail with its current interpretation of the NSR and NSPS rules,
the Company may be required to make significant capital expenditures which could
have a material adverse affect on the Company's financial position and results
of operations.
COMPLIANCE WITH ENVIRONMENTAL LAWS AND REGULATIONS
The normal course of operations of the Company necessarily involves activities
and substances that expose the Company to potential liabilities under laws and
regulations protecting the environment. Liabilities under these laws and
regulations can be material and in some instances may be imposed without regard
to fault, or may be imposed for past acts, even though such past acts may have
been lawful at the time they occurred. Sources of potential environmental
liabilities include (but are not limited to) the Federal Comprehensive
Environmental Response Compensation and Liability Act of 1980 and other similar
statutes.
The Company records its environmental liabilities when site assessments and/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 $8.3 million. The ultimate cost to clean up the Company's identified
sites may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as: the extent and nature of
contamination; the scarcity of reliable data for identified sites; and the time
periods over which site remediation is expected to occur. The Company believes
that, due to these uncertainties, it is remotely possible that cleanup costs
could exceed its recorded liability by up to $21.1 million. The upper limit of
this range of costs was estimated using assumptions least favorable to the
Company.
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LABOR UNION NEGOTIATIONS
The collective bargaining agreement between the Company and the International
Brotherhood of Electrical Workers Local Union 611 ("IBEW") which covers the
approximately 654 bargaining unit employees in the regulated and competitive,
deregulated operations expired on May 1, 2000, but continued in full force and
effect while the parties negotiated. On July 18, 2000 the IBEW gave the Company
notice of its intent to terminate the current collective bargaining agreement in
30 days. In an effort to resolve their differences, the Company and the IBEW
have requested and have met with a Federal mediator. In addition, the IBEW has
filed a charge with the National Labor Relations Board ("NLRB") alleging the
Company has bargained in bad faith, and by its actions has committed an unfair
labor practice. The Company has received a complaint and offer of settlement
issued by the local field office of the NLRB. The offer of settlement is not
acceptable to the Company, and the Company will pursue a formal hearing. The
Company continues to evaluate options in the event the parties do not achieve a
successor agreement. A dispute between the Company and employees representing
IBEW that results in a strike could have a material adverse effect on 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 Navajo Nation regarding these tax issues.
NEW AND PROPOSED ACCOUNTING STANDARDS
Decommissioning: The Staff of the Securities and Exchange Commission ("SEC") has
questioned certain of the current accounting practices of the electric industry
regarding the recognition, measurement and classification of decommissioning
costs for nuclear generating stations in financial statements of electric
utilities. In February 2000, the Financial Accounting Standards Board ("FASB")
issued an exposure draft regarding Accounting for Obligations Associated with
the Retirement of Long-Lived Assets ("Exposure Draft"). The Exposure Draft
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requires the recognition of a liability for an asset retirement obligation at
fair value. In addition, present value techniques used to calculate the
liability must use a credit adjusted risk-free rate. Subsequent remeasures of
the liability would be recognized using an allocation approach. The Company has
not yet determined the impact of the Exposure Draft.
EITF Issue 99-14, Recognition of Impairment Losses on Firmly Committed Executory
Contracts: The Emerging Issues Task Force ("EITF") has added an issue to its
agenda to address impairment of leased assets. A significant portion of the
Company's nuclear generating assets are held under operating leases. Based on
the alternative accounting methods being explored by the EITF, the related
financial impact of the future adoption of EITF Issue No. 99-14 should not have
a material adverse effect on results of operations. However, a complete
evaluation of the financial impact from the future adoption of EITF Issue No.
99-14 will be undeterminable until EITF deliberations are completed and stranded
cost recovery issues are resolved.
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities, ("SFAS 133"): SFAS 133 establishes
accounting and reporting standards requiring derivative instruments to be
recorded in the balance sheet as either an asset or liability measured at its
fair value. SFAS 133 also requires that changes in the derivatives' fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met. Special accounting for qualifying hedges allows derivative gains and
losses to offset related results on the hedged item in the income statement, and
requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. In June 1999, FASB
issued SFAS 137 to amend the effective date for the compliance of SFAS 133 to
January 1, 2001. In June 2000, the FASB issued SFAS 138 that provides certain
amendments to SFAS 133. The amendments, among other things, expand the normal
sales and purchases exception to contracts that implicitly or explicitly permit
net settlement and contracts that have a market mechanism to facilitate net
settlement. The expanded exception excludes a significant portion of the
Company's contracts that previously would have required valuation under SFAS
133. The Company is in the process of reviewing and identifying all financial
instruments currently existing in the Company in compliance with the provisions
of SFAS 133 and SFAS 138. As a result of the SFAS 138 amendment to SFAS 133, the
Company does not believe that the impact of SFAS 133 will be material as most of
the Company's derivative instruments result in physical delivery or are
marked-to-market under EITF 98-10.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
The Private Securities Litigation Reform Act of 1995 (the "Act") provides a
"safe harbor" for forward-looking statements to encourage companies to provide
prospective information about their companies without fear of litigation so long
as those statements are identified as forward-looking and are accompanied by
meaningful, cautionary statements identifying important factors that could cause
actual results to differ materially from those projected in the statement. Words
such as "estimates," "expects," "anticipates," "plans," "believes," "projects,"
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and similar expressions identify forward-looking statements. Accordingly, the
Company hereby identifies the following important factors which could cause the
Company's actual financial results to differ materially from any such results
which might be projected, forecasted, estimated or budgeted by the Company in
forward-looking statements: (i) adverse actions of utility regulatory
commissions; (ii) utility industry restructuring; (iii) failure to recover
stranded costs and transition costs; (iv) the inability of the Company to
successfully compete outside its traditional regulated market; (v) the success
of the Company's growth strategies particularly as it relates to PowerCo; (vi)
regional economic conditions, which could affect customer growth; (vii) adverse
impacts resulting from environmental regulations; (viii) loss of favorable fuel
supply contracts or inability to negotiate new fuel supply contracts; (ix)
failure to obtain water rights and rights-of-way; (x) operational and
environmental problems at generating stations; (xi) the cost of debt and equity
capital; (xii) weather conditions; and (xiii) technical developments in the
utility industry.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company uses derivative financial instruments in limited instances to manage
risk as it relates to changes in natural gas and electric prices and adverse
market changes for investments held by the Company's various trusts. The Company
is exposed to credit losses in the event of non-performance or non-payment by
counterparties. The Company uses a credit management process to assess and
monitor the financial conditions of counterparties. The Company also uses, on a
limited basis, certain derivative instruments for bulk power electricity trading
purposes in order to take advantage of favorable price movements and market
timing activities in the wholesale power markets. Information about market risk
is set forth in Note 4 to the Notes to the Consolidated Financial Statements and
incorporated by reference. The following additional information is provided.
The Company uses value at risk ("VAR") to quantify the potential exposure to
market movement on its open contracts and excess generating assets. The VAR is
calculated utilizing the variance/co-variance methodology over a three day
period within a 99% confidence level.
The Company's VAR as of June 30, 2000 from its electric trading contracts and
gas purchase contracts was $33.3 million. The significant increase in VAR from
the previous quarter is due to high wholesale prices and increased price
volatility caused by unseasonably warm weather and limited power generation
capacity in the Company's regional markets. The Company's VAR includes contracts
on its excess physical generating capacity in addition to open contracts. The
Company expects to cover its net open contract positions with its own excess
generating capacity (see footnote (4) in NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS). In addition, the imposition of a $250 per MWH price cap by the
California ISO will influence the VAR in the future (see "ITEM 2-MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-EFFECTS
OF CERTAIN EVENTS ON FUTURE REVENUES").
The Company's VAR is regularly monitored by the Company's Risk Management
Committee which is comprised of senior finance and operations managers. The Risk
Management Committee has put in place procedures to ensure that increases in VAR
are reviewed and, if deemed necessary, acted upon to reduce exposures.
The VAR represents an estimate of the reasonably possible net losses that would
be recognized on the portfolio of derivatives assuming hypothetical movements in
future market rates, 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 from estimates due to actual
fluctuations in market rates, operating exposures, and the timing thereof, as
well as changes to the portfolio of derivatives during the year.
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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 1999 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.
City of Gallup Complaint
As previously reported, in 1998 Gallup, Gallup Joint Utilities and the Pittsburg
& Midway Coal Mining Co. ("Pitt-Midway") filed a joint complaint and petition
("Complaint") with the NMPUC (predecessor of the PRC). The Complaint sought an
interim declaratory order stating, among other things, that Pitt-Midway is no
longer an obligated customer of the Company, Gallup is entitled to serve
Pitt-Midway and the Company must wheel power purchased by Gallup from other
suppliers over the Company's transmission system. In September 1998, the NMPUC
issued an order without conducting a hearing, granting the requests sought in
the Complaint. On October 13, 1999, the Supreme Court issued an opinion and
order annulling and vacating the NMPUC Order and remanding the NMPUC order to
the PRC.
On May 2, 2000, the PRC issued an order reactivating the case on remand
concluding that in should consider whether any portion of the NMPUC's final
order on remand should be readopted consistent with the Supreme Court's opinion
and order, and any other issues and requests for relief raised by the parties in
the proceedings on remand. The order also assigned the case to the hearing
examiner for a recommended decision. Although Gallup and Pitt - Midway
subsequently withdrew their request, on June 29, 2000, the hearing examiner
recommended dismissal of this case with prejudice. On July 25, 2000, the PRC
issued a final order adopting the hearing examiners recommendation.
In addition, hearings were held at the FERC in late February, regarding the
issue of whether the Company - Gallup Agreement requires the Company to transmit
power to Gallup for delivery at the Yah-Ta-Hey Substation. On May 16, 2000, FERC
ruled in the Company's favor, which ruling became final June 26, 2000.
San Diego Gas and Electric Company ("SDG&E") Complaints
As previously reported, SDG&E had filed four separate and similar complaints
with the FERC, alleging that certain charges under the Company's 100 MW power
sales agreement with SDG&E were unjust, unreasonable and unduly discriminatory.
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The first two of the complaints were dismissed by the FERC in 1999. On March 23,
2000, SDG&E filed a fifth complaint raising arguments previously made. The FERC
consolidated this fifth complaint for consideration with the two remaining SDG&E
complaints on the FERC's docket.
On June 8, 2000, the Presiding FERC Administrative Law Judge entered an Initial
Decision Terminating Proceedings (the "Initial Decision"). The Initial Decision
found that SDG&E would be unable to satisfy its burden of proof in the pending
complaints because the evidence did not support a finding that the rates at
issue were contrary to the public interest. Accordingly, the Administrative Law
Judge ordered, subject to review by the FERC on appeal or upon its own motion,
that the proceeding be terminated. The result of the Initial Decision was
tantamount to a decision on the merits favorable to PNM.
On July 20, 2000, the FERC entered its Notice of Finality of Initial Decision
stating that the FERC had decided not to initiate review of the Initial Decision
and determining that the Initial Decision was a final order of the FERC.
Purported Navajo Environmental Regulation
As previously reported, in July 1995 the Navajo Nation enacted the Navajo Nation
Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water
Act and the Navajo Nation Pesticide Act (collectively, the "Acts"). Pursuant to
the Acts, the Navajo Nation Environmental Protection Agency is authorized to
promulgate regulations covering air quality, drinking water and pesticide
activities, including those that occur at Four Corners. In February 1998, the
EPA issued regulations specifying provisions of the Clean Air Act for which it
is appropriate to treat Indian tribes in the same manner as states. The EPA
indicated that it believes that the Clean Air Act generally would supersede
pre-existing binding agreements that may limit the scope of tribal authority
over reservations. In February 1999, the EPA issued regulations under which
Federal operating permits for stationary sources in Indian Country can be issued
pursuant to Title V of the Clean Air Act. The regulations rely on authority
contained in an earlier rule in which the EPA outlined treatment of tribes as
states under the Clean Air Act. The Company as a participant in the Four Corners
Power Plant ("Four Corners") and as operating agent and joint owner of San Juan
Generating Station, and owners of other facilities located on other reservations
located in New Mexico, has filed appeals to contest the EPA's authority under
the regulations.
On July 14, 2000, the United States Court of Appeals for the District of
Columbia issued its opinion denying the Company's motion for rehearing of the
decision denying claims concerning the interpretation by EPA of tribal authority
under the Clean Air Act. The Company is currently evaluating the decision and
will have until October 10, 2000 to consider the filing of a petition for writ
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of certiorari to the United States Supreme Court. The Company cannot predict the
outcome of this proceeding or any subsequent determinations by the EPA. 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.
Texas-New Mexico Power Company ("TNMP") Complaint
TNMP filed a complaint against the Company at the Federal Energy Regulatory
Commission ("FERC") on March 15, 2000. TNMP alleges that the Company has
interpreted its Open Access Transmission Tariff on file with the FERC in an
unjust, unreasonable, and unduly discriminatory manner in violation of section
205 of the Federal Power Act with respect to the provision governing the right
of an existing firm transmission customer to extend transmission service at the
end of its contract term. On June 15, 2000, FERC denied TNP's complaint on the
grounds that the Company's interpretation of the OATT provision was not
unreasonable.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Annual Meeting
The annual meeting of shareholders was held on June 6, 2000. The matters voted
on at the meeting and the results were as follows:
The approval of the agreement and plan of share exchange under which the Company
will reorganize into a holding company structure. Manzano Corporation, a New
Mexico corporation formed by the company, will become the parent company and
will trade on the New York Stock Exchange under the symbol "MZO."
Votes
Against
Votes for or Withheld Abstentions
--------- ----------- -----------
28,701,001 2,813,624 221,815
The election of the following three nominees to serve as directors until the
annual meeting of shareholders in 2003, or until their successors are duly
elected and qualified, as follows:
Votes
Against
Director Votes For Or Withheld
-------- --------- -----------
Robert G. Armstrong 34,260,237 549,673
Theodore F. Patlovich 33,910,143 899,767
Paul F. Roth 34,252,699 557,211
As reported in the Definitive 14A Proxy Statement filed April 24, 2000, the name
of each other director whose term of office as director continues after the
meeting is as follows:
John T. Ackerman
Joyce A. Godwin
Manuel Lujan, Jr.
Benjamin F. Montoya
Robert M. Price
Jeffry E. Sterba
The approval of the selection by the Company's board of directors of Arthur
Andersen LLP as independent auditors for the fiscal year ending December 31,
2000, was voted on, as follows:
Votes
Against
Votes for or Withheld Abstentions
--------- ----------- -----------
34,627,252 107,370 75,287
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The meeting was adjourned until June 26, 2000 without a vote to adopt a new
performance equity plan as reported in the Definitive 14A Proxy Statement filed
April 24, 2000.
On June 26, 2000, the shareholders approved the Manzano Corporation Omnibus
Performance Equity Plan.
Votes
Against
Votes for or Withheld Abstentions
--------- ----------- -----------
21,852,029 10,217,732 401,045
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
10.34 Settlement Agreement between Public Service Company of New
Mexico and Creditors of Meadows Resources, Inc. dated
November 2, 1989 (refiled).
10.34.1 First amendment dated April 24, 1992 to the Settlement
Agreement dated November 2, 1989 among Public Service
Company of New Mexico, the lender parties thereto and
collateral agent (refiled).
15.0 Letter Re: Unaudited Interim Financial Information
27 Financial Data Schedule
b. Reports on Form 8-K:
Report dated and filed May 23, 2000 reporting New Mexico regulators set new date
for Electric Choice.
Report dated and filed June 5, 2000 announcing the Company's plan for
transitioning to a competitive retail electric power market in New Mexico.
Report dated and filed June 8, 2000 reporting PNM shareholders approve Holding
Company and Jeff Sterba succeeds Benjamin Montoya as Chief Executive Officer.
Report dated and filed June 8, 2000 reporting that PNM declared common and
preferred stock dividends.
Report dated and filed July 12, 2000 reporting that PNM welcomes Navoapache
Electric Cooperative as a wholesale customer.
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Signature
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW MEXICO
--------------------------------------
(Registrant)
Date: August 14, 2000 /s/ John R. Loyack
--------------------------------------
John R. Loyack
Vice President, Corporate Controller
and Chief Accounting Officer
(Officer duly authorized to
sign this report)
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