UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITES EXCHANGE ACT OF 1934
For the period ended September 30, 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 39,082,599 shares
---------------------------- -----------------
Class Outstanding at November 1, 2000
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
INDEX
Page No.
PART I. FINANCIAL INFORMATION:
Report of Independent Public Accountants......................... 3
ITEM 1. FINANCIAL STATEMENTS
Consolidated Statements of Earnings -
Three Months and Nine Months Ended September 30, 2000 and 1999... 4
Consolidated Balance Sheets -
September 30, 2000 and December 31, 1999......................... 5
Consolidated Statements of Cash Flows -
Nine Months Ended September 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........... 23
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK............................................. 56
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS.......................................... 57
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K........................... 60
Signature.............................................................. 62
2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of Public Service Company of New Mexico:
We have reviewed the accompanying condensed consolidated balance sheet of PUBLIC
SERVICE COMPANY OF NEW MEXICO (a New Mexico corporation) and subsidiaries as of
September 30, 2000, and the related condensed consolidated statements of
earnings for the three-month and nine-month periods ended September 30, 2000 and
1999, and the condensed consolidated statements of cash flows for the nine-month
periods ended September 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 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
November 10, 2000
3
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- ----------------------
2000 1999 2000 1999
--------- -------- ---------- ---------
(In thousands, except per share amounts)
Operating Revenues:
Electric......................................... $ 444,101 299,767 $ 943,681 $ 697,073
Gas.............................................. 55,133 38,249 204,193 171,432
Unregulated businesses........................... 243 2,588 1,935 6,288
--------- -------- ---------- ---------
Total operating revenues....................... 499,477 340,604 1,149,809 874,793
--------- -------- ---------- ---------
Operating Expenses:
Cost of energy sold.............................. 316,519 180,730 664,636 399,093
Energy production costs.......................... 32,854 32,980 104,402 104,019
Administrative and general....................... 36,926 42,079 102,683 112,707
Depreciation and amortization.................... 23,022 23,313 69,664 69,739
Transmission and distribution costs.............. 14,537 14,357 44,614 43,870
Taxes, other than income taxes................... 9,103 9,652 25,234 27,821
Income 19,064 7,218 32,523 22,954
taxes............................................
--------- -------- ---------- ---------
Total operating expenses....................... 452,025 310,329 1,043,756 780,203
--------- -------- ---------- ---------
Operating income............................... 47,452 30,275 106,053 94,590
--------- -------- ---------- ---------
Other Income and Deductions, Net of Tax............ 15,569 8,455 29,827 20,867
--------- -------- ---------- ---------
Income before interest charges................. 63,021 38,730 135,880 115,457
Net interest charges............................... 16,108 17,329 49,029 52,754
--------- -------- ---------- ---------
Net Earnings from Continuing Operations............ 46,913 21,401 86,851 62,703
Cumulative Effect of a Change in
Accounting Principle, Net of Tax................. - - - 3,541
--------- -------- ---------- ---------
Net Earnings....................................... 46,913 21,401 86,851 66,244
Preferred Stock Dividend Requirements.............. 147 147 440 440
--------- -------- ---------- ---------
Net Earnings Applicable to Common Stock............ $ 46,766 $ 21,254 $ 86,411 $ 65,804
========= ======== ========== =========
Net Earnings per Common Share:
Basic............................................ $ 1.19 $ 0.52 $ 2.18 $ 1.60
========= ======== ========== =========
Diluted.......................................... $ 1.18 $ 0.52 $ 2.17 $ 1.60
========= ======== ========== =========
Dividends Paid per Share of Common Stock........... $ 0.20 $ 0.20 $ 0.60 $ 0.60
========= ======== ========== =========
The accompanying notes are an integral part of these financial statements.
4
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2000 1999
------------ -----------
(Unaudited)
ASSETS (In thousands)
- ------
Utility Plant:
Electric plant in service......................................... $1,983,785 $1,976,009
Gas plant in service.............................................. 491,413 483,819
Common plant in service and plant held for future use............. 69,469 69,273
---------- ----------
2,544,667 2,529,101
Less accumulated depreciation and amortization.................... 1,135,175 1,077,576
---------- ----------
1,409,492 1,451,525
Construction work and progress.................................... 162,239 104,934
Nuclear fuel, net of accumulated amortization of
$22,923 and $20,832............................................ 27,221 25,923
---------- ----------
Net utility plant............................................... 1,598,952 1,582,382
---------- ----------
Other Property and Investments:
Other investments................................................. 468,615 483,008
Non-utility property, net of accumulated
depreciation of $1,555 and $1,261............................. 3,713 4,439
---------- ----------
Total other property and investments............................ 472,328 487,447
---------- ----------
Current Assets:
Cash and cash equivalents......................................... 119,073 120,399
Accounts receivables, net of allowance for
uncollectible accounts of $5,796 and $12,504.................. 217,102 147,746
Other receivables................................................. 44,929 68,911
Inventories....................................................... 33,718 33,064
Regulatory assets................................................. 6,010 24,056
Other current assets.............................................. 22,393 11,862
---------- ----------
Total current assets............................................ 443,225 406,038
---------- ----------
Deferred Charges:
Regulatory assets................................................. 227,134 195,898
Prepaid benefit costs............................................. 17,619 16,126
Other deferred charges............................................ 32,922 35,377
---------- ----------
Total current assets............................................ 277,675 247,401
---------- ----------
$2,792,180 $2,723,268
========== ==========
5
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2000 1999
----------- -----------
(Unaudited)
CAPITALIZATION AND OTHER LIABILITIES (In thousands)
- ------------------------------------
Capitalization:
Common stockholders' equity:
Common stock.................................................... $ 195,588 $ 203,517
Additional paid-in capital...................................... 432,250 453,393
Accumulated other comprehensive income, net of tax.............. 1,472 2,352
Retained earnings............................................... 290,718 227,829
----------- -----------
Total common stockholders' equity............................ 920,028 887,091
Minority interest.................................................. 12,211 12,771
Cumulative preferred stock without mandatory
Redemption requirements....................................... 12,800 12,800
Long-term debt, less current maturities............................ 953,808 988,489
----------- -----------
Total capitalization......................................... 1,898,847 1,901,151
----------- -----------
Current Liabilities:
Accounts payable................................................... 171,653 150,645
Accrued interest and taxes......................................... 55,299 34,237
Other current liabilities.......................................... 68,256 60,948
----------- -----------
Total current liabilities.................................... 295,208 245,830
----------- -----------
Long-Term Liabilities:
Accumulated deferred income taxes.................................... 150,242 153,179
Accumulated deferred investment tax credits.......................... 48,639 50,996
Regulatory liabilities............................................... 68,690 88,497
Regulatory liabilities related to accumulated deferred income tax.... 15,091 15,091
Accrued postretirement benefit costs................................. 12,046 8,945
Other liabilities.................................................... 303,417 259,579
----------- -----------
Total long-term liabilities....................................... 598,125 576,287
----------- -----------
Commitments and Contingencies..........................................
- -
----------- -----------
$2,792,180 $2,723,268
=========== ===========
The accompanying notes are an integral part of these financial statements.
6
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
-------------------
2000 1999
-------- --------
(In thousands)
Cash Flows From Operating Activities:
Net earnings............................................................. $ 86,851 $ 66,244
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization........................................ 77,728 78,447
Gain on cumulative effect of a change in accounting principle........ - (5,862)
Other, net........................................................... (15,531) (3,691)
Changes in certain assets and liabilities:
Accounts receivables............................................... (69,350) (31,181)
Other assets....................................................... 40,416 25,087
Accounts payable................................................... 20,997 2,310
Other liabilities.................................................. 26,652 18,048
--------- ---------
Net cash flows provided from operating activities.................. 167,763 149,402
--------- ---------
Cash Flows From Investing Activities:
Utility plant additions.................................................. (97,738) (60,881)
Return on PVNGS lease obligation bonds................................... 16,668 16,903
Other investing.......................................................... (2,506) 23,301
--------- ---------
Net cash flows used from investing activities...................... (83,576) (20,677)
--------- ---------
Cash Flows From Financing Activities:
Repayments............................................................... (32,800) (58,200)
Common stock repurchase.................................................. (27,875) (17,655)
Dividends paid........................................................... (24,275) (24,895)
Other financing.......................................................... (563) (635)
--------- ---------
Net cash flows used in financing activities........................ (85,513) (101,385)
--------- ---------
Decrease in Cash and Cash Equivalents...................................... (1,326) 27,340
Beginning of Period........................................................ 120,399 61,280
--------- ---------
End of Period.............................................................. $119,073 $ 88,620
========= =========
Supplemental Cash Flow Disclosures:
Interest paid............................................................ $ 50,393 $ 60,392
========= =========
Income taxes paid, net .................................................. $ 25,922 $ 27,525
========= =========
Acquired DOE pipeline in exchange for transportation services............ $ - $ 3,100
========= =========
The accompanying notes are an integral part of these financial statements.
7
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies and Responsibilities for Financial Statements
In the opinion of management of Public Service Company of New Mexico (the
"Company"), the accompanying interim consolidated financial statements present
fairly the Company's financial position at September 30, 2000 and December 31,
1999, the consolidated results of its operations for the three months and nine
months ended September 30, 2000 and the consolidated statements of cash flows
for the nine months ended September 30, 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
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
nine months ended September 30, 2000 and 1999 is as follows:
Utility
------------------------------------------------
Distribution Transmission Gas Total Generation Unregulated Consolidated
------------ ------------ --- ----- ---------- ----------- ------------
(In thousands)
Three Months Ended:
- ------------------
2000:
Operating revenues:
External customers............. $ 145,284 $ 4,686 $ 55,133 $ 205,103 $294,131 $ 243 $ 499,477
Intersegment revenues.......... - 8,091 - 8,091 90,638 - 98,729
Depreciation and amortization..... 5,993 2,096 4,989 13,078 9,938 6 23,022
Interest income (loss)............ 325 3 137 465 (1,529) 830 (234)
Net interest charges.............. 3,297 1,045 2,645 6,987 9,013 108 16,108
Income tax expense (benefit)
From continuing operations...... 8,603 982 (2,163) 7,422 4,520 (3,610) 8,332
Operating income (loss)........... 16,377 2,575 2,862 21,814 32,461 (6,823) 47,452
Segment net income (loss)......... 13,882 1,530 3,921 19,333 37,705 (10,125) 46,913
Total assets...................... 574,324 194,588 419,579 1,188,491 1,447,513 156,176 2,792,180
Gross property additions.......... 16,134 272 13,350 29,756 (511) 46,850
17,605
1999:
Operating revenues:
External customers............. $ 143,442 $ 4,120 $ 38,249 $ 185,811 $152,205 $ 2,588 $ 340,604
Intersegment revenues.......... - 7,450 - 7,450 88,751 - 96,201
Depreciation and amortization..... 5,732 2,057 4,830 12,619 10,175 519 23,313
Interest income................... 28 1 559 588 10,133 1,757 12,478
Net interest charges.............. 3,999 1,119 3,008 8,126 8,961 242 17,329
Income tax expense (benefit)
from continuing operations...... 6,969 564 (1,836) 5,697 330 (4,081) 1,946
Operating income (loss)........... 14,706 2,055 (218) 16,543 17,099 (3,367) 30,275
Segment net income (loss)......... 10,699 917 (2,993) 8,623 13,768 (990) 21,401
Total assets...................... 571,252 185,569 403,818 1,160,639 1,254,341 160,394 2,575,374
Gross property additions.......... 7,116 3,576 6,626 17,318 3,442 326 21,086
9
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(2) Segment Information (Continued)
Utility
------------------------------------------------
Distribution Transmission Gas Total Generation Unregulated Consolidated
------------ ------------ --- ----- ---------- ----------- ------------
(In thousands)
Nine Months Ended:
- -----------------
2000:
Operating revenues:
External customers............. $393,534 $ 12,500 $204,193 $ 610,227 $ 537,647 $ 1,935 $1,149,809
Intersegment revenues.......... - 21,952 - 21,952 245,330 - 267,282
Depreciation and amortization..... 18,298 6,303 14,870 39,471 30,175 18 69,664
Interest income (loss)............ 715 6 384 1,105 29,697 5,151 35,953
Net interest charges.............. 10,001 3,194 8,380 21,575 27,041 413 49,029
Income tax expense (benefit)
From continuing operations...... 20,825 2,023 716 23,564 1,738 (12,442) 12,860
Operating income (loss)........... 41,854 6,453 12,941 61,248 63,031 (18,226) 106,053
Segment net income (loss)......... 32,439 3,229 8,585 44,253 62,034 (19,436) 86,851
Total assets...................... 574,324 194,588 419,579 1,188,491 1,447,513 156,176 2,792,180
Gross property additions.......... 33,592 4,751 24,562 62,905 34,821 2,342 100,068
1999:
Operating revenues:
External customers............. $405,816 $ 11,632 $171,432 $ 588,880 $279,625 $ 6,288 $ 874,793
Intersegment revenues.......... - 22,351 - 22,351 245,919 - 268,270
Depreciation and amortization..... 17,054 6,183 14,234 37,471 30,708 1,560 69,739
Interest income................... 44 4 954 1,002 30,966 4,880 36,848
Net interest charges.............. 11,939 3,664 9,238 24,841 27,170 743 52,754
Income tax expense (benefit)
from continuing operations...... 19,784 1,873 1,019 22,676 (5,944) (8,685) 8,047
Operating income (loss)........... 42,711 6,751 10,710 60,172 44,149 (9,731) 94,590
Segment net income (loss)......... 30,384 3,024 983 34,391 36,007 (7,695) 62,703
Total assets...................... 571,252 185,569 403,818 1,160,639 1,254,341 160,394 2,575,374
Gross property additions.......... 20,120 8,631 17,291 46,042 13,650 1,216 60,908
10
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(3) Comprehensive Income
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -------------------
2000 1999 2000 1999
-------- -------- -------- ---------
(In thousands)
Net Earnings.................................... $46,913 $21,401 $86,851 $ 66,244
-------- -------- -------- ---------
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains arising during
the period.................................. 695 154 2,081 1,826
Less reclassification adjustment for gains
Included in net income.................... (1,013) (1,065) (2,961) (3,226)
-------- -------- -------- ---------
Total Other Comprehensive Income (Loss)...... (318) (911) (880) (1,400)
-------- -------- -------- ---------
Total Comprehensive Income...................... $46,595 $20,490 $85,971 $ 64,844
======== ======== ======== =========
The Company's investments held in grantor trusts for nuclear decommissoning 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. To date the
Company has not incurred a significant credit loss. The Company's credit risk
with its largest counterparty as of September 30, 2000 was $7.1 million.
11
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4) Financial Instruments (Continued)
Natural Gas Contracts
Pursuant to a 1997 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 are recoverable
through the Company's purchased gas adjustment clause as deemed prudently
incurred by the PRC. 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 contracted for gas price caps, a type of hedge, to protect its
natural gas customers from price risk during the 2000-2001 heating season
through the use of financial hedging tools. Pursuant to the PRC's final order on
November 7, 2000, the Company will limit its financial hedging strategy to a
cost of $5 million during this heating season. The Company will recover the $5
million in hedging costs during the months of October and November 2000 in equal
$2.5 million allotments as a component of the PGAC. The Company has purchased
options which will effectively cap the purchased gas price at a weighted average
price of $5.62 per MMBTU for its normal winter purchases for the months of
December and January.
Fuel Hedging
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 of $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. A portion of financial
instruments settled in the third quarter and the remaining will settle in the
fourth quarter. The Company is accounting for these transactions as hedges;
12
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4) Financial Instruments (Continued)
accordingly, gains and losses related to these transactions are deferred and
recognized in earnings as an adjustment to its cost of fuel.
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 September 30, 2000, the Company's wholesale electric trading operations
settled trading contracts for the sale of electricity that generated $71.7
million of electric revenues by delivering 1,810 million KWh. The Company
purchased $64.6 million or 1,668 million KWh of electricity to support these
contractual sale and other open market sales opportunities.
As of September 30, 2000, the Company had open trading contract positions to buy
$9.9 million and to sell $13.7 million of electricity. At September 30, 2000,
the Company had a gross mark-to-market gain (asset position) on these trading
contracts of $14.1 million and gross mark-to-market loss (liability position) of
$15.8 million, with net mark-to-market loss (liability position) of $1.7
million. The mark-to-market valuation is recognized in earnings each period.
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.
13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4) Financial Instruments (Continued)
The Company's wholesale power marketing operations, including both firm
commitments and trading activities, are managed through an asset backed
strategy, whereby the Company's aggregate net open position is covered by its
own excess generation capabilities. The Company is exposed to market risk if its
generation capabilities were disrupted or if its jurisdictional load
requirements were greater than anticipated. If the Company were required to
cover all or a portion of its net open contract position, it would have to meet
its commitments through market purchases. The Company's value-at-risk
calculation considers this exposure (see Item 3. Quantitative and Qualitative
Disclosure About Market Risk).
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. In October
2000, certain of these contracts were terminated. These new contracts increase
the downside protection and further limit the upside gain. The Company will
recognize a realized gain of $0.3 million in the fourth quarter. The Company
entered into similar contracts which expire on June 15, 2001. For the three
months ended September 30, 2000, the Company recorded net unrealized losses of
$0.5 million (pre-tax) on the market value of its options. For the nine months
ended September 30, 2000, the market value of its options remained unchanged.
The net effect of the collar instruments for the nine months ended September 30,
2000 was a net pre-tax gain of $2.4 million.
14
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
September 30 (in thousands, except per share data):
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
----------- ----------- ----------- -----------
Basic:
Net Earnings from Continuing Operations..................... $ 46,913 $ 21,401 $ 86,851 $ 62,703
Cumulative Effect of a Change in Accounting
Principle, net of tax ................................... 3,541
----------- ----------- ----------- -----------
Net Earnings................................................ 46,913 21,401 86,851 66,244
Preferred Stock Dividend Requirements....................... 147 147 440 440
----------- ----------- ----------- -----------
Net Earnings Applicable to Common Stock..................... $ 46,766 $ 21,254 $ 86,411 $ 65,804
=========== =========== =========== ===========
Average Number of Common Shares Outstanding................. 39,363 40,774 39,623 41,127
=========== =========== =========== ===========
Net Earnings per Common Share:
Earnings from continuing operations....................... 1.19 0.52 2.18 1.51
Cumulative effect of a change in accounting principle..... - - - 0.09
----------- ----------- ----------- -----------
Net Earnings per Common Share (Basic)....................... $ 1.19 $ 0.52 $ 2.18 $ 1.60
=========== =========== =========== ===========
Diluted:
Net Earnings Applicable to Common Stock
Used in basic calculation................................. $ 46,766 $ 21,254 $ 86,411 $ 65,804
=========== =========== =========== ===========
Average Number of Common Shares Outstanding................. 39,363 40,774 39,623 41,127
Diluted effect of common stock equivalents (a).............. 288 92 125 74
----------- ----------- ----------- -----------
Average common and common equivalent shares
Outstanding.............................................. 39,651 40,866 39,748 41,201
=========== =========== =========== ===========
Net Earnings per Common Share:
Earnings from continuing operations....................... $ 1.18 $ 0.52 $ 2.17 $ 1.51
Cumulative effect of a change in accounting principle..... - - - 0.09
----------- ----------- ----------- -----------
Net Earnings per Share of Common Stock (Diluted)............ $ 1.18 $ 0.52 $ 2.17 $ 1.60
=========== =========== =========== ===========
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out-of-the-money options of 92,949 and 37,838 for the three
months ended 2000 and 1999, respectively and 140,448 and 52,446 for the
nine months ended 2000 and 1999, respectively.
15
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 nine
months ended September 30, 2000 and the year ended December 31, 1999:
September 30, December 31,
2000 1999
------------- -----------
Allowance for doubtful accounts, beginning
of year......................................... $ 12,504 $ 836
Bad debt accrual.................................. 5,022 11,496
Less: Write-off (adjustments) of uncollectible
Accounts........................................ 11,730 (172)
-------- ----------
Allowance for doubtful accounts, end of period ... $ 5,796 $ 12,504
======== ==========
The Company continues to analyze its delinquent accounts resulting from the
problems associated with the implementation of the new customer billing system.
As a result, the Company has determined that $11.7 million of customer
receivable will not be collectible. Based upon information available at
September 30, 2000, the Company believes the allowance for doubtful accounts of
$5.8 million is adequate for potential uncollectible accounts.
16
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies (Continued)
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 agreed to sell to the Company certain assets
acquired by Tri-State as the result of Tri-State's merger with Plains Electric
Generation and Transmission Cooperative, Inc. ("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 $4.5 million of this advance
represents an inducement for entering into a 10 year power sales agreement.
Accordingly, the Company has expensed 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. As of September 30, 2000, the Company repurchased
453,100 shares of its outstanding common stock at a cost of $9.8 million.
17
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies (Continued)
San Juan Coal Contract
On August 31, 2000, the Company, negotiated an agreement with the coal supplier
for San Juan Generating Station ("SJGS"). Under the terms of the agreement
between the Company, San Juan Coal Company ("SJCC") and Tucson Electric Power
Company ("TEP"), which also owns a portion of the generating station, SJCC will
replace the two surface mining operations that now supply the plant with a
single underground mine located on the site of one of the existing surface
mines. In addition to the closure of the surface mines, the Company and TEP will
no longer require the coal transportation services provided by San Juan
Transportation Company ("SJTC").
Nuclear Decommissioning Trust
As previously reported, in 1998, the Company and the trustee of the Company's
master decommissioning trust sued several companies and individuals, in State
District Court in Santa Fe County, for the under-performance of a corporate
owned life insurance program. The program was used to fund a portion of the
Company's nuclear decommissioning obligations for its 10.2% interest in PVNGS.
In August, 1999, the Company filed an interlocutory appeal of one of the trial
court's decisions regarding discovery to the New Mexico Court of Appeals. On
June 22, 2000, the Court issued an opinion agreeing with the Company's argument
and reversed the trial court. Subsequently, the parties reached a settlement
agreement under which the complaint and counterclaim were dismissed with
prejudice on September 5, 2000 and the Company and trustee received $13.8
million in settlement proceeds.
Gas Rate Orders
On October 24, 2000, the PRC issued a final order approving a stipulation
negotiated in the third quarter between the Company and the PRC staff which
resolved all issues raised by the two remanded gas rate cases. The final order
adds approximately $1.2 million to the Company's revenues in the final quarter
of 2000, $4.7 million in 2001, and $3.9 million in 2002. The Company has
reversed certain reserves against costs recovered in the settlement that were
recorded against earnings at the time of the original regulatory orders,
resulting in a one-time pre-tax gain of $4.6 million. This amount will be
collected from customers in rates over the next 12 years.
18
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies (Continued)
Other
There are various claims and lawsuits pending against the Company and certain of
its subsidiaries. The Company is also subject to Federal, state and local
environmental laws and regulations, and is currently participating in the
investigation and remediation of 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.
19
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 has identified 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 and the internal review of
contracts, 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 Event
On November 9, 2000 the Company and Western Resources, Inc. (Western Resources)
announced that both companies' boards of directors approved an agreement under
which the Company will acquire the Western Resources electric utility operations
in a tax-free, stock-for-stock transaction.
Under the terms of the agreement, the Company and Western Resources, whose
utility operations consist of its Kansas Power and Light division and Kansas Gas
and Electric subsidiary, will both become subsidiaries of a new holding company
to be named at a future date. Prior to the consummation of this combination,
Western Resources will reorganize all of its non-utility assets, including its
85 percent stake in Protection One and its 45 percent investment in ONEOK, into
Westar Industries which will be spun off to Western Resources' shareholders.
20
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(8) Subsequent Event (Continued)
The new holding company will issue 55 million of its shares, subject to
adjustment, to Western Resources' shareholders and Westar Industries. Before any
adjustments, the new company will have approximately 95 million shares
outstanding, of which approximately 42.1 percent will be owned by former the
Company shareholders and 57.9 percent will be owned by former Western Resources
shareholders and Westar Industries. Westar Industries will receive a portion of
such shares in repayment of a $234 million obligation currently owed by Western
Resources to Westar Industries.
Based on the Company's average closing price over the last ten days prior to the
announcement of $27.325 per share, the indicated equity consideration of the
transaction is approximately $1.503 billion, including conversion of the Westar
Industries obligation. In addition, the new holding company will assume
approximately $2.939 billion of existing Western Resources' debt, giving the
transaction an aggregate enterprise value of approximately $4.442 billion. The
new holding company will have a total enterprise value of approximately $6.5
billion ($2.6 billion in equity; $3.9 billion in debt and preferred stock).
The transaction will be accounted for as a reverse acquisition by the Company as
Western Resources shareholders will receive the majority of the voting interests
in the new holding company. For accounting purposes Western Resources will be
treated as the acquiring entity. Accordingly, all of the assets and liabilities
of the Company will be recorded at fair value in the business combination as
required by the purchase method of accounting. In addition, the operations of
the Company will be reflected in the reported results of the combined company
only from the date of acquisition.
The companies expect the transaction to be completed within the next 12 to 15
months. The new holding company will serve over one million retail electric
customers and 400,000 retail gas customers in New Mexico and Kansas and will
have generating capacity of more than 7,000 megawatts. The transaction exceeds
the Company's stated goal of doubling its generation capacity and tripling its
power sales more than three years ahead of schedule. The transaction will also
make the new company a leading energy supplier in the Western and Midwestern
wholesale markets.
The rationale for this transaction is the acceleration of the Company's proven
growth strategy, consistent with its targeted 10 percent annual average earnings
growth. The Company expects only modest cost savings and does not have a present
intention to have significant involuntary workforce reductions as a result of
the transaction. The new holding company will seek to minimize any workforce
effects through reduced hiring, attrition, and other appropriate measures. All
existing labor agreements will be honored.
21
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(8) Subsequent Event (Continued)
In the transaction, each Company share will be exchanged on a one-for-one basis
for shares in the new holding company. Each Western Resources share will be
exchanged for a fraction of a share of the new company. This exchange ratio will
be finalized at closing, depending on the impact of certain adjustments to the
transaction consideration. Since Western Resources and Westar Industries remain
committed to reducing Western Resources' net debt balance prior to consummation
of the transaction, they have agreed with the Company on a mechanism to adjust
the transaction consideration based on additional equity contributions. Under
this mechanism, Western Resources could undertake certain activities not
affecting the utility operations to reduce the net debt balance of the utility.
The effect of such activities would be to increase the number of new holding
company shares to be issued to all Western Resources shareholders (including
Westar Industries) in the transaction. In addition, Westar Industries has the
option of making additional equity infusions into Western Resources that will be
used to reduce the utility's net debt balance prior to closing. Up to $407
million of such equity infusions may be used to purchase additional new holding
company common and convertible preferred stock.
At closing, Jeffrey E. Sterba, present chairman, president and chief executive
officer of the Company, will become chairman, president and chief executive
officer of the new holding company, and David C. Wittig, present chairman,
president and chief executive officer of Western Resources, will become
chairman, president and chief executive officer of Westar Industries. The Board
of Directors of the new company will consist of six current Company board
members and three additional directors, two of whom will be selected by the
Company from a pool of candidates nominated by Western Resources, and one of
whom will be nominated by Westar Industries. The new holding company will be
headquartered in New Mexico. Headquarters for the Kansas utilities will remain
in Kansas.
Shareholders of the new holding company will receive the Company's dividend. The
Company's current annual dividend is $0.80 per share.
The successful spin-off of Westar Industries from Western Resources is required
prior to the consummation of the transaction. The transaction is also
conditioned upon, among other things, approvals from both companies'
shareholders and customary regulatory approvals from the Kansas Corporation
Commission, the New Mexico Public Regulation Commission, the Federal Energy
Regulatory Commission, the Nuclear Regulatory Commission, and the Department of
Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The new
holding company expects to register as a holding company with the Securities and
Exchange Commission under the Public Utility Holding Company Act of 1935.
22
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 September 30, 2000 and 1999 and
December 31, 1999, approximately 370,000, 363,000 and 366,000, respectively,
retail electric customers were served by the Company.
The Company owns or leases 2,781 circuit miles of transmission lines,
interconnected with other utilities east into Texas, west into Arizona, and
north into Colorado and Utah. Due to rapid load growth in recent years, most of
the capacity on this transmission system is fully committed and there is no
additional access available on a firm commitment basis. These factors, together
with significant physical constraints in the system, limit the ability to wheel
power into the Company's service area from outside the state.
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 430,000, 417,000 and 426,000 customers as of September 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.
23
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 Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
-------- -------- -------- --------
Retail ................. $ 24,074 $ 22,712 $117,712 $108,009
Commercial ............. 7,032 5,037 31,963 28,954
Transportation* ........ 3,651 2,853 10,582 9,824
Other .................. 20,376 7,647 43,936 24,645
-------- -------- -------- --------
$ 55,133 $ 38,249 $204,193 $171,432
======== ======== ======== ========
The following table shows gas throughput by customer class:
GAS THROUGHPUT
(Thousands of decatherms)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
------ ------ ------ ------
Retail ..................... 2,246 2,497 17,166 21,193
Commercial ................. 1,033 1,206 6,188 7,572
Transportation* ............ 14,905 11,817 34,579 30,203
Other ...................... 3,919 2,099 8,881 6,430
------ ------ ------ ------
22,103 17,619 66,814 65,398
====== ====== ====== ======
*Customer-owned gas.
24
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
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 Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
-------- -------- -------- --------
Jurisdictional sales ............... $144,355 $148,843 $391,140 $409,744
Firm-requirement wholesale ......... 1,554 1,865 5,179 5,317
Other contracted off-system sales .. 154,377 98,586 282,881 172,357
Economy energy sales ............... 123,570 50,223 246,196 96,774
Other* ............................. 20,245 250 18,285 12,881
-------- -------- -------- --------
$444,101 $299,767 $943,681 $697,073
======== ======== ======== ========
The following table shows electric sales by customer class:
ELECTRIC SALES BY MARKET
(Megawatt hours)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---------- ---------- ---------- ----------
Jurisdictional sales ............ 1,978,568 1,899,636 5,355,379 5,159,835
Firm-requirement wholesale ...... 49,747 45,779 144,503 133,654
Other contracted off-system sales 2,214,133 1,960,184 5,728,874 4,821,785
Economy ......................... 1,029,641 1,602,380 3,729,391 3,292,851
---------- ---------- ---------- ----------
5,272,089 5,507,979 14,958,147 13,408,125
========== ========== ========== ==========
* Includes mark-to-market gains/(losses). See footnote (4) in Notes to
Consolidated Financial Statements.
25
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
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 September 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 (6) 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. In July 2000, Avistar loaned $1.5 million to AMDAX.com. The proceeds of
the note and all accrued but unpaid interest is to be paid to Avistar on March
31, 2001 or earlier if AMDAX.com meets certain investment or financing
conditions.
ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS
On November 9, 2000 the Company and Western Resources, Inc. (Western Resources)
announced that both companies' boards of directors approved an agreement under
which the Company will acquire the Western Resources electric utility operations
in a tax-free, stock-for-stock transaction.
26
Under the terms of the agreement, the Company and Western Resources, whose
utility operations consist of its Kansas Power and Light division and Kansas Gas
and Electric subsidiary, will both become subsidiaries of a new holding company
to be named at a future date. Prior to the consummation of this combination,
Western Resources will reorganize all of its non-utility assets, including its
85 percent stake in Protection One and its 45 percent investment in ONEOK, into
Westar Industries which will be spun off to Western Resources' shareholders.
The new holding company will issue 55 million of its shares, subject to
adjustment, to Western Resources' shareholders and Westar Industries. Before any
adjustments, the new company will have approximately 95 million shares
outstanding, of which approximately 42.1 percent will be owned by former the
Company shareholders and 57.9 percent will be owned by former Western Resources
shareholders and Westar Industries. Westar Industries will receive a portion of
such shares in repayment of a $234 million obligation currently owed by Western
Resources to Westar Industries.
Based on the Company's average closing price over the last ten days prior to the
announcement of $27.325 per share, the indicated equity consideration of the
transaction is approximately $1.503 billion, including conversion of the Westar
Industries obligation. In addition, the new holding company will assume
approximately $2.939 billion of existing Western Resources' debt, giving the
transaction an aggregate enterprise value of approximately $4.442 billion. The
new holding company will have a total enterprise value of approximately $6.5
billion ($2.6 billion in equity; $3.9 billion in debt and preferred stock).
The transaction will be accounted for as a reverse acquisition by the Company as
Western Resources shareholders will receive the majority of the voting interests
in the new holding company. For accounting purposes Western Resources will be
treated as the acquiring entity. Accordingly, all of the assets and liabilities
of the Company will be recorded at fair value in the business combination as
required by the purchase method of accounting. In addition, the operations of
the Company will be reflected in the operations of the combined company only
from the date of acquisition.
The companies expect the transaction to be completed within the next 12 to 15
months. The new holding company will serve over one million retail electric
customers and 400,000 retail gas customers in New Mexico and Kansas and will
have generating capacity of more than 7,000 megawatts. The transaction exceeds
the Company's stated goal of doubling its generation capacity and tripling its
power sales more than three years ahead of schedule. The transaction will also
make the new company a leading energy supplier in the Western and Midwestern
wholesale markets.
27
The rationale for this transaction is the acceleration of the Company's proven
growth strategy, consistent with its targeted 10 percent annual average earnings
growth. The Company expects only modest cost savings and does not have a present
intention to have significant involuntary workforce reductions as a result of
the transaction. The new holding company will seek to minimize any workforce
effects through reduced hiring, attrition, and other appropriate measures. All
existing labor agreements will be honored.
In the transaction, each Company share will be exchanged on a one-for-one basis
for shares in the new holding company. Each Western Resources share will be
exchanged for a fraction of a share of the new company. This exchange ratio will
be finalized at closing, depending on the impact of certain adjustments to the
transaction consideration. Since Western Resources and Westar Industries remain
committed to reducing Western Resources' net debt balance prior to consummation
of the transaction, they have agreed with the Company on a mechanism to adjust
the transaction consideration based on additional equity contributions. Under
this mechanism, Western Resources could undertake certain activities not
affecting the utility operations to reduce the net debt balance of the utility.
The effect of such activities would be to increase the number of new holding
company shares to be issued to all Western Resources shareholders (including
Westar Industries) in the transaction. In addition, Westar Industries has the
option of making additional equity infusions into Western Resources that will be
used to reduce the utility's net debt balance prior to closing. Up to $407
million of such equity infusions may be used to purchase additional new holding
company common and convertible preferred stock.
At closing, Jeffrey E. Sterba, present chairman, president and chief executive
officer of the Company, will become chairman, president and chief executive
officer of the new holding company, and David C. Wittig, present chairman,
president and chief executive officer of Western Resources, will become
chairman, president and chief executive officer of Westar Industries. The Board
of Directors of the new company will consist of six current Company board
members and three additional directors, two of whom will be selected by the
Company from a pool of candidates nominated by Western Resources, and one of
whom will be nominated by Westar Industries. The new holding company will be
headquartered in New Mexico. Headquarters for the Kansas utilities will remain
in Kansas.
Shareholders of the new holding company will receive the Company's dividend. The
Company's current annual dividend is $0.80 per share.
The successful spin-off of Westar Industries from Western Resources is required
prior to the consummation of the transaction. The transaction is also
conditioned upon, among other things, approvals from both companies'
shareholders and customary regulatory approvals from the Kansas Corporation
Commission, the New Mexico Public Regulation Commission, the Federal Energy
Regulatory Commission, the Nuclear Regulatory Commission, and the Department of
Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The new
holding company expects to register as a holding company with the Securities and
Exchange Commission under the Public Utility Holding Company Act of 1935. The
Company expects that all of the above mentioned approvals will be obtained,
however, such approvals are not assured.
28
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.
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.
29
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 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 has been completed and briefs are being filed. 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 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"). The Hearing Examiner
has tentatively scheduled hearings on Part three to begin on June 6, 2001.
Hearings are expected to last four to six weeks. The Company's management
believes that implementation of the separation plan will not occur prior to the
second quarter of 2001. However, there is no assurance that implementation of
the separation plan will occur by that time. Under existing deadlines, the
Company must separate its assets no later than August 1, 2001.
On August 17, 2000, the PRC staff and other parties filed a Joint Motion to
Defer Commission Decision on Separation of Generation Assets and to Extend the
Standard Offer Update Deadline. The Joint Motion requested that the PRC not
allow separation to occur until after the 2001 legislative session to allow the
legislature to determine if any amendments to the Restructuring Act might be
necessary in light of the high prices experienced this summer in San Diego,
California. The 2001 legislative session begins January 16 and ends March 17. On
September 11, 2000, the Company filed its response to the Joint Motion, pointing
out key differences between New Mexico's Restructuring Act and California's as
well as differing circumstances between the two states. On September 26, 2000,
the PRC conducted a workshop where numerous interested parties commented on the
California experience and its relevance to New Mexico. To date, the PRC has not
acted on the Joint Motion.
The Company is currently in discussions with the PRC staff and other parties in
an attempt to arrive at a settlement agreement which addresses the concerns of
the parties and allows separation to continue without significant delay. The
final outcome of these discussions is unknown; however, the potential outcome of
these discussions may be different from the plan the Company filed on May 31,
2000 and could potentially affect the realizability of certain regulatory assets
recorded by the Company (See Other Issues Facing the Company - The Restructuring
Act and Formation of the Holding Company - Stranded Costs Recovery).
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.
30
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. The announcement of the acquisition of Western
Resources electric utility businesses on November 9, 2000, will allow the
Company to meet this goal well ahead of schedule as the Western Resources
acquisition will add approximately 5,600 megawatts to the Company's generation
portfolio growth. The Company will continue to pursue growth in its generation
portfolio and intends to spend $400 to $800 million over the next five years to
achieve generation portfolio growth. Such growth will be dependent upon the
Company's ability to generate funds for 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 have been a number of proposals on electric
restructuring being considered with no concrete timing for definitive actions.
None of these proposals have been acted upon by Congress. Issues such as
stranded cost recovery, market power, utility regulation reform, the role of
states, subsidies, consumer protections and environmental concerns are expected
to be reintroduced if not acted upon in the current Congressional session. In
addition, the FERC has stated that if Congress mandates electric retail access,
it should leave the details of the program to the states with the FERC having
the authority to order the necessary transmission access for the delivery of
power for the states' retail access programs.
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.
31
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.
Three Months Ended September 30, 2000
Compared to Three Months Ended September 30, 1999
The table below sets forth the operating results as percentages of total
operating revenues for each business segment.
Three Months Ended September 30, 2000
Utility
-----------------------------------------------
Electric Gas Generation
----------------------- ---------------------- --------------------
Operating revenues:
External customers................. 149,970 99.88% 55,133 100.00% 294,131 76.44%
Intersegment revenues.............. 177 0.12% - - 90,638 23.56%
---------- ---------- --------- ---------- -------- ---------
Total revenues..................... 150,147 100.00% 55,133 100.00% 384,769 100.00%
---------- ---------- --------- ---------- -------- ---------
Cost of energy sold.................. 1,442 0.96% 30,776 55.82% 284,301 73.89%
Intercompany trans. price............ 90,638 60.37% - 0.00% 177 0.05%
---------- ---------- --------- ---------- -------- ---------
Total fuel costs................... 92,080 61.33% 30,776 55.82% 284,478 73.93%
---------- ---------- --------- ---------- -------- ---------
Gross Margin......................... 58,067 38.67% 24,357 44.18% 100,291 26.07%
---------- ---------- --------- ---------- -------- ---------
Administrative and other costs....... 9,795 6.52% 8,281 15.02% 9,584 2.49%
Energy production costs.............. 296 0.20% 328 0.59% 32,230 8.38%
Depreciation and amortization........ 8,089 5.39% 4,989 9.05% 9,938 2.58%
Transmission and distribution costs.. 8,520 5.67% 6,019 10.92% 0.00%
-
Taxes other than income taxes........ 2,938 1.96% 1,613 2.93% 2,215 0.58%
Income taxes......................... 9,478 6.31% 265 0.48% 13,863 3.60%
---------- ---------- --------- ---------- -------- ---------
Total non-fuel operating expenses.. 39,116 26.05% 21,495 38.99% 67,830 17.63%
---------- ---------- --------- ---------- -------- ---------
Operating income..................... $ 18,951 12.62% $ 2,862 5.19% 32,461 8.44%
---------- ---------- --------- ---------- -------- ---------
Three Months Ended September 30, 1999
Utility
-----------------------------------------------
Electric Gas Generation
----------------------- ---------------------- --------------------
Operating revenues:
External customers................. 147,562 99.88% 38,249 100.00% 152,205 63.17%
Intersegment revenues.............. 177 0.12% - 0.00% 88,752 36.83%
---------- ---------- --------- ---------- -------- ---------
Total revenues..................... 147,739 100.00% 38,249 100.00% 240,957 100.00%
---------- ---------- --------- ---------- -------- ---------
Cost of energy sold.................. 1,125 0.76% 14,500 37.91% 165,105 68.52%
Intercompany trans. price............ 88,751 60.07% - 0.00% 177 0.07%
---------- ---------- --------- ---------- -------- ---------
Total fuel costs................... 89,876 60.83% 14,500 37.91% 165,282 68.59%
---------- ---------- --------- ---------- -------- ---------
Gross Margin......................... 57,863 39.17% 23,749 62.09% 75,675 31.41%
---------- ---------- --------- ---------- -------- ---------
Administrative and other costs....... 12,419 8.41% 11,956 31.26% 11,279 4.68%
Energy production costs.............. 648 0.44% 345 0.90% 30,631 12.71%
Depreciation and amortization........ 7,789 5.27% 4,830 12.63% 10,175 4.22%
Transmission and distribution costs.. 7,315 4.95% 7,044 18.42% - 0.00%
Taxes other than income taxes........ 5,380 3.64% 1,777 4.65% 2,472 1.03%
Income taxes......................... 7,553 5.11% (1,989) (5.20)% 4,019 1.67%
---------- ---------- --------- ---------- -------- ---------
Total non-fuel operating expenses.. 41,104 27.82% 23,963 62.65% 58,576 24.31%
---------- ---------- --------- ---------- -------- ---------
Operating income..................... $16,759 11.34% (214) (0.56)% 17,099 7.10%
---------- ---------- --------- ---------- -------- ---------
32
UTILITY OPERATIONS
Electric Business Unit - Operating revenues increased $2.4 million (1.6%) for
the period to $150.1 million due to increased retail electricity delivery of
1.98 million MWh compared to 1.90 million MWh delivered in the comparable period
last year, a 4.2% improvement, partially offset by the implementation of the
rate order in late July 1999 (which lowered rates by $3.8 million quarter over
quarter - see Other Issues Facing the Company - Electric Rate Case) and the
absence of electric franchise tax revenues. Franchise taxes were a part of the
Company's rate structure in the prior year. In the current year, they have been
unbundled from the rate structure. As a result, the Company if now a collection
agent for such taxes and does not incur expense or generate revenues as a result
of collecting such taxes.
The gross margin, or operating revenues minus cost of energy sold, increased
slightly $0.2 million. However, gross margin as a percentage of revenues
decreased 0.5%. 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 $2.6 million (21.1%) for the period.
This decrease is due to costs related to Year 2000 ("Y2K") compliance which did
not recur in 2000, reduced costs related to implementing a customer billing
system and lower associated bad debt expense. As a percentage of revenues,
administrative and other costs decreased to 6.5% from 8.4% for the period ended
September 30, 2000 and 1999, respectively, primarily as a result of reduced
costs.
Depreciation and amortization increased $0.3 million (3.9%) for the period. The
increase is due to the impact of amortizing the costs of the new customer
billing system. Depreciation and amortization as a percentage of revenues
increased from 5.3% to 5.4% reflecting a slight increase in expense.
Transmission and distribution costs increased $1.2 million (16.5%) for the
quarter primarily due to increased maintenance of transmission lines and station
related equipment for reliability purposes. As a percentage of revenues,
transmission and distribution costs increased from 5.0% to 5.7%.
Gas Business Unit - Operating revenues increased $16.9 million (44.1%) for the
period to $55.1 million. This increase was driven by a 31.3% increase in the
average rate charges per decatherm due to higher gas prices and a 25.4% volume
increase. Residential and commercial volume decreased 11.4%, while customers
other than residential and commercial volume increased 35.3%. This growth was
primarily attributed to industrial and transportation customers such as the
Company's power generating business whose demand increased due to the warm
summer. In October 2000, the PRC issued a final order approving a settlement
regarding two rate cases (see "OTHER ISSUES FACING THE COMPANY - GAS RATE
ORDERS").
33
The gross margin, or operating revenues minus cost of energy sold, increased
$0.6 million (2.6%). This increase is due to higher distribution volumes. The
Company purchases natural gas in the open market and resells natural gas to
customers at cost. As a result, the increase in gas prices does not have an
impact on the Company's margin or profits.
Administrative and general costs decreased $3.7 million (30.7%). This decrease
is mainly due to non-recurring Y2K compliance costs in 1999, customer billing
system costs and lower associated bad debt expenses.
Depreciation and amortization increased $0.2 million (3.3%). The increase is due
to the impact of amortizing the costs of a new customer billing system.
Transmission and distribution expenses decreased $1.0 million (14.6%) for the
period. The decrease is primarily due to non-recurring Y2K compliance costs.
GENERATION OPERATIONS
Operating revenues grew $143.8 million (59.7%) for the period to $384.8 million.
This increase in wholesale electricity sales reflects strong regional wholesale
electric prices caused by an unseasonably warm summer, limited power generation
capacity and increasing natural gas prices. These factors contributed to
unusually high wholesale prices which continued from the second quarter 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 3.3 million
MWh of electricity this period compared to 3.6 million MWh delivered last year,
a decrease of 8.7%. The MWh decrease is attributable to less trading activity
during the third quarter of 2000. The higher prices and greater volatility
combined with prudent risk management caused the decrease in the trading
activities. Wholesale revenues to third-party customers increased from $152.2
million to $294.1 million, a 93.3% increase. Wholesale revenues were positively
impacted by a $12.1 million realized gain the Company recognized 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
$24.6 million (32.5%). However, gross margin as a percentage of revenues
decreased 5.3%. This decline reflects higher fuel and purchased power costs due
to higher market prices.
Administrative and general costs decreased $1.7 million (15.0%) for the period
due to lower legal costs related to a lawsuit involving the Company's
decommissioning trust which was settled in the third quarter (see Consolidated
results of operations discussion) and non-recurring Y2K compliance cost in 1999,
partially offset by a one time charge of $4.5 million in connection with the
acquisition of a new, long-term wholesale customer in July (see Footnote (6) of
the Consolidated Financial Statements). As a percentage of revenues,
administrative and other decreased to 2.5% from 4.7% for the period ended
September 30, 2000 and 1999, respectively primarily as a result of reduced
costs.
34
Energy production costs increased $1.6 million (5.2%) for the period. The
increase is due to higher San Juan costs due to bonuses paid related to the
agreement reached with the labor union (see "OTHER ISSUES FACING THE COMPANY -
LABOR UNION NEGOTIATIONS"), higher outside services related to a strike
contingency, higher limestone expense and additional maintenance projects in the
current year. As a percentage of revenues, energy production costs decreased
from 12.7% to 8.4%. The decrease is primarily due to a significant increase in
energy sales.
UNREGULATED BUSINESSES
Avistar contributed $0.2 million in revenues for the period compared to $2.6
million in the comparable prior year period due to lower business volumes.
Operating losses for Avistar remained constant at $1.2 million in the current
year compared to the prior year.
CONSOLIDATED
Corporate administrative and general costs increased $3.7 million for the
period. This increase was due to higher legal costs, work force bonus accruals
due to increased earnings and other administrative costs, partially offset by
non-recurring Y2K compliance costs in 1999. As a percentage of revenues,
corporate administrative and general costs increased to 1.4% from 1.2% due to
the increase in costs.
Other income and deductions, net of taxes, increased $7.1 million for the period
to $15.6 million due to one-time net gains of $8.3 million related to the
settlement of a lawsuit (See PART II - OTHER INFORMATION - ITEM 1. - LEGAL
PROCEEDINGS - Nuclear Decommission Trust), and $2.8 million for the reversal of
certain reserves associated with the expected resolution of two gas rate cases
(see OTHER ISSUES FACING THE COMPANY - GAS RATE ORDERS), partially offset by
expenses related to business development, valuation losses recognized for
certain investments, expenses related to the transfer of the management of the
City of Santa Fe's water system to the municipality and decreased gains on the
corporate hedge (see Footnote (4) to the Consolidated Financial Statements).
Net interest charges decreased $1.2 million for the period to $16.1 million
primarily as a result of the retirement of $10.0 million of senior unsecured
notes in August 1999 and $32.8 million in January 2000.
The Company's consolidated income tax expense was $29.8 million, an increase of
$17.0 million for the quarter. The Company's income tax effective rate increased
from 37.4% to 38.8% primarily due to the tax effects of the 1994 and 1995 IRS
exam and the Arizona state audit.
The Company's net earnings from continuing operations for the quarter ended
September 30, 2000, were $38.5 million, excluding one-time gains for the lawsuit
settlement and the reversal of certain gas rate case reserves and a one-time
charge in connection with the acquisition of a new, long-term wholesale customer
("One-Time Items") compared to $21.4 million for the quarter ended September 30,
1999, a 79.9% increase. Earnings per share from continuing operations on a
diluted basis were $0.97 (excluding the One-Time Items) compared to $0.52 for
the quarter ended September 30, 2000 and 1999, respectively. Diluted weighted
average shares outstanding were 39.7 million and 40.9 million in 2000 and 1999,
respectively. The decrease reflects the common stock repurchase program in 1999
and 2000. The increase in earnings for the quarter was primarily due to the
Company's continued success in the wholesale power market, warmer temperatures
in 2000 compared to 1999, and ongoing efforts to control costs.
35
Nine Months Ended September 30, 2000 Compared to
Nine Months Ended September 30, 1999
The table below sets forth the operating results as percentages of total
operating revenues for each business segment.
Nine Months Ended September 30, 2000
Utility
--------------------------------------------
Electric Gas Generation
---------------------- -------------------- --------------------
Operating revenues:
External customers.................... 406,034 99.87% 204,193 100.00% 537,647 68.67%
Intersegment revenues................. 530 0.13% - - 245,330 31.33%
---------- ---------- --------- --------- ---------- ---------
Total revenues........................ 406,564 100.00% 204,193 100.00% 782,977 100.00%
---------- ---------- --------- --------- ---------- ---------
Cost of energy sold..................... 3,707 0.91% 118,706 58.13% 542,223 69.25%
Intercompany trans. Price............... 245,330 60.34% - 0.00% 530 0.07%
---------- ---------- --------- --------- ---------- ---------
Total fuel costs...................... 249,037 61.25% 118,706 58.13% 542,753 69.32%
---------- ---------- --------- --------- ---------- ---------
Gross Margin............................ 157,527 38.75% 85,487 41.87% 240,224 30.68%
---------- ---------- --------- --------- ---------- ---------
Administrative and other costs.......... 27,298 6.71% 27,586 13.51% 18,279 2.33%
Energy production costs................. 924 0.23% 1,117 0.55% 102,361 13.07%
Depreciation and amortization........... 24,601 6.05% 14,870 7.28% 30,175 3.85%
Transmission and distribution costs..... 24,385 6.00% 20,198 9.89% 23 0.00%
Taxes other than income taxes........... 9,433 2.32% 5,421 2.65% 7,550 0.96%
Income taxes............................ 22,579 5.55% 3,354 1.64% 18,805 2.40%
---------- ---------- --------- --------- ---------- ---------
Total non-fuel operating expenses..... 109,220 26.86% 72,546 35.53% 177,193 22.63%
---------- ---------- --------- --------- ---------- ---------
Operating income........................ $48,307 11.88% $12,941 6.34% $63,031 8.05%
---------- ---------- --------- --------- ---------- ---------
Nine Months Ended September 30, 1999
Utility
--------------------------------------------
Electric Gas Generation
-------------------- --------------------- --------------------
Operating revenues:
External customers..................... 417,448 99.87% 171,432 100.00% 279,625 53.21%
Intersegment revenues.................. 530 0.13% - 0.00% 245,919 46.79%
--------- --------- ---------- --------- ---------- ---------
Total revenues......................... 417,978 100.00% 171,432 100.00% 525,544 100.00%
--------- --------- ---------- --------- ---------- ---------
Cost of energy sold...................... 3,360 0.80% 83,180 48.52% 312,553 59.47%
Intercompany trans. Price................ 245,919 58.84% - 0.00% 530 0.10%
--------- --------- ---------- --------- ---------- ---------
Total fuel costs....................... 249,279 59.64% 83,180 48.52% 313,083 59.57%
--------- --------- ---------- --------- ---------- ---------
Gross Margin............................. 168,699 40.36% 88,252 51.48% 212,461 40.43%
--------- --------- ---------- --------- ---------- ---------
Administrative and other costs........... 34,359 8.22% 34,679 20.23% 25,605 4.87%
Energy production costs.................. 1,819 0.44% 1,067 0.62% 98,136 18.67%
Depreciation and amortization............ 23,237 5.56% 14,234 8.30% 30,708 5.84%
Transmission and distribution costs...... 22,707 5.43% 21,144 12.33% 20 0.00%
Taxes other than income taxes............ 15,164 3.63% 5,076 2.96% 7,318 1.39%
Income taxes............................. 21,953 5.25% 1,339 0.78% 6,525 1.24%
--------- --------- ---------- --------- ---------- ---------
Total non-fuel operating expenses...... 119,239 28.53% 77,539 45.23% 168,312 32.03%
--------- --------- ---------- --------- ---------- ---------
Operating income......................... $49,460 11.83% $10,713 6.25% $44,149 8.40%
--------- --------- ---------- --------- ---------- ---------
36
UTILITY OPERATIONS
Electric Business Unit - Operating revenues declined $11.4 million (2.7%) for
the period to $406.6 million due to the implementation of the rate order in late
July 1999 (which lowered rates by $22.2 million year-over-year) and unfavorable
price mix due to mild weather conditions, partially offset by increased retail
electricity delivery of 5.36 million MWh compared to 5.16 million MWh delivered
in the prior year period, a 3.8% improvement.
The gross margin, or operating revenues minus cost of energy sold, decreased
$11.2 million reflecting a decrease in gross margin as a percentage of revenues
of 1.6%. 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 $7.1 million (20.6%) for the period.
This decrease is due to non-recurring Y2K compliance costs, customer billing
system costs and lower associated bad debt accruals. As a percentage of
revenues, administrative and other costs decreased to 6.7% from 8.2% for the
nine months ended September 30, 2000 and 1999, respectively primarily as a
result of reduced costs.
Depreciation and amortization increased $1.4 million (5.9%) 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 6.1% reflecting an increase in expense and the decrease in retail energy
sales.
Transmission and distribution costs increased $1.7 million (7.4%) for the year
primarily due to increased maintenance of transmission lines and station related
equipment for reliability purposes. As a percentage of revenues, transmission
and distribution costs increased from 5.4% to 6.0%. This increase was primarily
the result of an increase in costs and the decrease in retail energy sales.
Taxes other than income decreased $5.7 million (37.8%) due to a change in the
recognition of electric franchise fees. Taxes other than income as a percentage
of revenues decreased to 2.32% from 3.63% reflecting the decrease in expense.
Energy production costs decreased $0.9 million (49.2%) for the year primarily
due to non-recurring Y2K compliance costs in 1999. As a percentage of revenues,
energy production costs decreased from 0.49% to 0.23% due to a decrease in
costs.
Gas Business Unit - Operating revenues increased $32.8 million (19.1%) for the
period to $204.2 million. This increase was driven by a 20.0% increase in the
average rate charges per decatherm due to strong gas prices despite a mild
winter and warm spring, and a 2.2% volume increase. Residential and commercial
customers volume decreased 20.0% while customers other than residential and
commercial volume increased 19.4%. This growth was primarily attributed to
industrial and transportation customers such as the Company's power generating
business whose demand increased due to the warm spring and summer.
37
The gross margin, or operating revenues minus cost of energy sold, decreased
$2.8 million (3.1%). This decrease is due to a switch in the default rate for
access fees.
Administrative and general costs decreased $7.1 million (20.5%). This decrease
is mainly due to non-recurring Y2K compliance costs, customer billing system
costs and lower associated bad debt accruals.
Depreciation and amortization increased $0.6 million (4.5%) for the period. The
increase is due to the impact of amortizing the costs of a new customer billing
system.
Transmission and distribution costs decreased $0.9 million (4.5%) primarily due
to non-recurring Y2K compliance costs.
GENERATION OPERATIONS
Operating revenues grew $257.4 million (49.0%) for the period to $783.0 million.
The Company delivered wholesale (bulk) power of 9.60 million MWh of electricity
this period compared to 8.25 million MWh delivered last year, an increase of
16.4% (see Results of Operations - Three Months Ended September 30, 2000
Compared to Three Months Ended September 30, 1999 for a discussion of factors
affecting results in the third quarter of 2000).
The gross margin, or operating revenues minus cost of energy sold, increased
$27.8 million. However, gross margin as a percentage of revenues decreased from
40.4% to 30.7% reflecting 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 $7.3 million (28.6%) for the period.
This decrease is due to lower legal costs related to a lawsuit involving the
Company's decommissioning trust, a PVNGS interruption and liability insurance
refund and non-recurring Y2K compliance costs, partially offset by a one-time
charge of $4.5 million in connection with the acquisition of a new, long-term
wholesale customer (see Footnote (6) of the Consolidated Financial Statements).
As a percentage of revenues, administrative and other decreased to 2.3% from
4.9% for the nine months ended September 30, 2000 and 1999, respectively as a
result of reduced costs and increased revenues.
Energy production costs increased $4.2 million (4.3%) for the period. These
costs are generation related. The increase is due to higher maintenance costs of
$3.2 million due to scheduled outages at San Juan Unit 3 and Four Corners Unit
4, partially offset by lower operations expenses of $2.0 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 18.7% to 13.1%. The decrease is primarily due to a significant increase in
energy sales.
UNREGULATED BUSINESSES
Avistar contributed $1.9 million in revenues for the period compared to $6.3
million in the comparable prior year period due to lower business volumes.
Operating losses for Avistar decreased from $3.2 million in the prior year to
$2.9 million in the current year.
38
CONSOLIDATED
Corporate administrative and general costs increased $12.6 million for the
period. This increase was due to higher legal costs, work force 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 $9.0 million for the period
to $29.8 million due to one-time net gains of $8.3 million related to the
settlement of a lawsuit and $2.8 million for the reversal of certain reserves
associated with the expected resolution of two gas rate cases, partially offset
by expenses related to business development, valuation losses recognized for
certain investments, expenses related to the transfer of the management of the
City of Santa Fe's water system to the municipality and decreased gains on 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 $3.7 million for the period to $49.0 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 $52.2 million, an increase of $15.6 million for the
year. The Company's income tax effective rate, before the cumulative effect of
the accounting change, increased from 36.9% to 37.5% primarily due to the tax
effects of the 1994 and 1995 IRS exam and the Arizona state audit.
The Company's net earnings from continuing operations for the year-to-date
period ended September 30, 2000, were $78.5 million, excluding one-time gains
for the lawsuit settlement and the reversal of certain gas rate case reserves
and a one-time charge in connection with the acquisition of a new, long-term
wholesale customer ("One-Time Items") compared to $65.0 million, excluding the
one-time gain related to mine closure activities ("One-Time Gain") for the
year-to-date period ended September 30, 1999. Earnings per share from continuing
operations excluding the cumulative effect of the accounting change on a diluted
basis were $1.96 (excluding the One-Time Items) compared to $1.54 (excluding the
One-Time Gain) for the year-to-date period ended September 30, 1999. Diluted
weighted average shares outstanding were 39.7 million and 41.2 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.
39
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.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2000, the Company had working capital of $148.0 million
including cash and cash equivalents of $119.1 million. This is a decrease in
working capital of $12.2 million from December 31, 1999. This decrease is
primarily the result of an increased use of cash for investing purposes, the
timing of accounts payable and accrued tax payments 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 $167.8 million, an increase of
$18.4 million from 1999. This increase was primarily the result of increased
profitability including the settlement of a lawsuit. In addition, the recovery
of purchased gas adjustments from utility customers and lower income tax
payments contributed to the increase. This increase was partially offset by an
increase in accounts receivable 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 1998 and 1999 (see Other Issues Facing the Company -
Implementation of New Billing System).
Cash used for investing activities was $83.6 million in the nine months ended
September 30, 2000 compared to $20.7 million for the nine months ended September
30, 1999. This increased spending reflects $13.4 million relating to the
acquisition of transmission assets (see "Acquisition of Certain Assets and
Related Agreements"), the expansion of the electric distribution system of $12.6
million for reliability and to serve new load, 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 nine months ended September 30, 1999).
Cash used for financing activities was $85.5 million in the nine months ended
September 30, 2000 compared to $101.4 million for the nine months ended
September 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 common stock repurchases in 2000 (see "Stock
Repurchase").
40
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
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 nine months ended September 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 November 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 November 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.
In connection with the Company's announcement of its proposed acquisition of
Western Resources' electric utility operations, Standard and Poors ("S&P"),
Moody's Investor Services ("Moody's") and Fitch IBCA, Duff & Phelps ("Fitch")
have placed its securities ratings on negative credit watch pending review of
the transaction. The Company is committed to maintain its investment grade.
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". Fitch IBCA, Duff & Phelps ("Fitch") 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.
41
In addition to the impact of the proposed acquisition of Western Resources'
electric utility operations, 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 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 structure of the Proposed Plan presented in the
April 18, 2000 Form 8-K was subsequently revised in October 2000 by the Company.
This revised Proposed Plan results in a capital structure for Manzano, PowerCo
and UtilityCo similar to the presentation in the Form 8-K. The revised Proposed
Plan is subject to regulatory and other approvals as well as market, economic
and business conditions. As such, the revised 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.
42
The revised Proposed Plan assumes that the Asset Transfer will be accomplished
as follows: PowerCo will transfer its regualted assets to a wholly-owned
subsdiary, UtilityCo, in exchange for common stock, UtilityCo preferred stock,
UtilityCo senior unsecured notes and cash. UtilityCo will also assume certain
liabilities associated with the regulated assets. PowerCO will then dividend the
common stock of UtilityCo to Manzano.
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 the revised 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. From August 8, 2000 through September 30, 2000
Company repurchased an additional 453,100 shares of its outstanding common stock
at a cost of $9.8 million.
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
acquired by Tri-State as the result of Tri-State's merger with Plains Electric
Generation and Transmission Cooperative, Inc. ("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.
43
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 $4.5 million of this advance
represents an inducement for entering into a 10 year power sales agreement.
Accordingly, the Company has expensed 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.
San Juan Coal Contract
On August 31, 2000, the Company negotiated an agreement with the coal supplier
for San Juan Generating Station ("SJGS"). Under the terms of the agreement
between the Company, San Juan Coal Company ("SJCC") and Tucson Electric Power
Company ("TEP"), which also owns a portion of the generating station, SJCC will
replace the two surface mining operations that now supply the plant with a
single underground mine located on the site of one of the existing surface
mines. In addition to the closure of the surface mines, the Company and TEP will
no longer require the coal transportation services provided by San Juan
Transportation Company ("SJTC").
The revised coal contract is expected to save the Company between $400 million
and $500 million in fuel costs over the next 17 years. Besides saving on fuel
costs, the cleaner-burning, less abrasive coal is expected to reduce the
Company's share of the plant's maintenance and operating expenses by
approximately $2 million per year. The plant is expected to realize some of the
benefits of the higher quality coal next year, as the existing surface mines are
phased out and the underground mine is developed. The underground mine is
scheduled to be in full production by November 2002.
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.
Capital Structure
The Company's capitalization, including current maturities of long-term debt is
shown below:
September 30, December 31,
2000 1999
------------- ------------
Common Equity....................... 49.1 % 47.3 %
Preferred Stock..................... 0.7 0.7
Long-term Debt...................... 50.2 52.0
------- -------
Total Capitalization*............ 100.0 % 100.0 %
======= =======
* Total capitalization does not include as debt the present value ($162.7
million as of September 30, 2000 and $165.2 million as of December 31, 1999) of
the Company's lease obligations for PVNGS Units 1 and 2 and EIP.
44
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 under existing PRC orders. Completion of corporate separation
will require a number of regulatory approvals by, among others, the PRC and the
Securities and Exchange Commission. Approvals from the Federal Energy Regulatory
Commission and the Nuclear Regulatory Commission have been obtained. Hearings on
the corporate separation have been completed before a PRC hearing examiner, and
briefs have been submitted. Other parties to the PRC case have asked for delays
in approval until after the New Mexico legislature has had a chance in the first
quarter of 2001 to act based on the recent deregulation experience in
California. The Company is unable to predict whether a delay will be granted.
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 September 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
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).
45
Approximately $134 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.
If the current discussions with the PRC staff and other parties result in a
settlement in which the amount the Company recovers for stranded costs is less
than the amount it has recorded on the balance sheet as regulatory assets, the
Company will be required to write-off the difference between its recovery of
these costs and the amount it has currently recorded. The final outcome of these
discussions is unknown at the current time (see "Restructuring the Electric
Utility Industry").
46
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
transition costs are currently being capitalized and will be amortized over the
recovery period to match related revenues. The Company intends to vigorously
pursue remedies available to it should the PRC disallow recovery of reasonable
transition costs. Costs not recoverable will be expensed when incurred unless
these costs are otherwise permitted to be capitalized under current and future
accounting rules. If the amount of non-recoverable transition costs is material,
the resulting charge to earnings may have a material effect on the future
financial results and position of the Company.
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 Businesses 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.
47
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.
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.
48
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
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.
49
The following is a summary of the allowance for doubtful accounts during for the
three months ended September 30, 2000 and year ended December 31, 1999:
September 30, December 31,
2000 1999
------------- -----------
(In thousands)
Allowance for doubtful accounts, beginning
of year............................................ $ 12,504 $ 836
Bad debt accrual..................................... 5,022 11,496
Less: Write off (adjustments) of uncollectible
Accounts........................................... 11,730 (172)
-------- ---------
Allowance for doubtful accounts, end of period ...... $ 5,796 $ 12,504
======== =========
The Company continues to analyze its delinquent accounts resulting from the
problems associated with the implementation of the new customer billing system.
As a result, the Company has determined that $11.7 million of customer
receivables will not be collectible. Based upon information available at
September 30, 2000, the Company believes the allowance for doubtful accounts of
$5.8 million is adequate for management's estimate of potential uncollectible
accounts.
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 would be considered in a separate proceeding before the
PRC. Hearings on this issue have not yet been scheduled. The PRC is considering
briefs submitted by the parties addressing the scope of the proceeding. KAFB has
not renewed its electric 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 was remanded to the PRC. 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.
50
Rate Case Settlement
On October 24, 2000, the PRC issued a final order approving a stipulation
negotiated in the third quarter between the Company and the PRC staff which
resolved all issues raised by the two remanded rate cases. The final order adds
approximately $1.2 million to the Company's revenues in the final quarter of
2000, $4.7 million in 2001, and $3.9 million in 2002. The Company has reversed
certain reserves against costs recovered in the settlement that were recorded
against earnings at the time of the original regulatory orders, resulting in a
one-time pre-tax gain of $4.6 million. This amount will be collected from
customers in rates over the next 12 years.
Effects of Certain EVENTS ON Future Revenues
During the second quarter, regional wholesale electricity prices reached $750
per MWh. In the third quarter, 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. 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. Price controls, such as those imposed in California, could have a
material adverse effect on the Generation Operations' revenue growth.
On November 1, 2000, the Federal Energy Regulatory Commission ("FERC") entered
an order in response to numerous complaints regarding events and prices in the
California markets in which it found that market structure these factors,
combined with an imbalance of supply and demand, caused and continue to have the
potential to cause unjust and unreasonable rates for sales of short term energy
under certain conditions. FERC therefore proposed changes to the auction
procedures in the California markets and enhanced reporting requirements for
sellers bidding a price in excess of $150 per MWh as a method for mitigating
prices that have been alleged to be excessive as well as other short and
longer-term remedies. FERC declined to order refunds for past collections, but
did confirm a refund obligation in a previous order, which it stated would cover
the period from October 2, 2000 through December 31, 2002 as a condition of
authorization to make sales at market rates. FERC did not order any refunds, but
attempted to establish a "circumscribed" refund liability, and stated that it
may order refunds if certain conditions are met, subject to certain to certain
cost-based limitations.
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. Nevertheless,
even if the DOE were to replace the Company as the power supplier to KAFB, any
resulting loss of revenue to the Company would be mitigated by selling the
associated energy into the wholesale power market.
51
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.
The Company has reached an agreement with SJCC and Tucson Electric Power ("TEP")
to replace these two surface mining operations with a single underground mine
located adjacent to the plant. Underground mining is expected to provide a
higher quality coal at a lower cost per ton. The new mine will use the longwall
mining technique and is expected to ramp to full station supply by the end of
2002.
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.
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).
52
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. 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. No complaint has been filed against the Company, and the Company
believes that all of the routine maintenance, repair, and replacement work
undertaken at its power plants was and continues to be in accordance with the
requirements of NSR and NSPS. However, by letter dated October 23, 2000, the New
Mexico Environment Department ("NMED") made an information request of the
Company, advising the Company that the NMED was in the process of assisting the
EPA in the EPA's nationwide effort "of verifying that changes made at the
country's utilities have not inadvertently triggered a modification under the
Clean Air Act's Prevention of Significant Determination ("PSD") policies." The
Company intends to respond in a timely fashion to the NMED information request.
The nature and cost of the impacts of EPA's changed interpretation of the
application of the NSR and NSPS, together with proposed changes to these
regulations, may be significant to the power production industry. However, the
Company cannot quantify these impacts with regard to its power plants. 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.
53
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.
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. The successor agreement was reached on
August 22, 2000 and was ratified by IBEW members on September 2, 2000. The
IBEW's 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 is pending. The Company will vigorously defend against the
Union's allegations.
54
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
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
55
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 identified 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 and the internal review of contracts, 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,"
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.
56
The Company uses value at risk ("VAR") to quantify the potential exposure to
market movement on its open contracts and excess generating assets. The VAR is
calculated utilizing the variance/co-variance methodology over a three day
period within a 99% confidence level. The Company's VAR as of September 30, 2000
from its electric trading contracts and gas purchase contracts was $18.9
million.
The Company's wholesale power marketing operations, including both firm
commitments and trading activities, are managed through an asset backed
strategy, whereby the Company's aggregate net open position is covered by its
own excess generation capabilities. The Company is exposed to market risk if its
generation capabilities were disrupted or if its jurisdictional load
requirements were greater than anticipated. If the Company were required to
cover all or a portion of its net open contract position, it would have to meet
its commitments through market purchases. The Company's value-at-risk
calculation considers this exposure.
The Company's VAR is regularly monitored by the Company's Risk Management
Committee which is comprised of senior finance and operations managers. The Risk
Management Committee has put in place procedures to ensure that increases in VAR
are reviewed and, if deemed necessary, acted upon to reduce exposures.
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.
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.
57
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 to
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. On June 29, 2000, the hearing examiner appointed to preside over the
case on remand recommended dismissal of this case with prejudice. On July 25,
2000, the PRC issued a final order adopting the hearing examiners
recommendation, which became nonappealable on August 24, 2000.
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, an
administrative law judge of the FERC ruled in the Company's favor, which ruling
became final August 10, 2000.
San Diego Gas and Electric Company ("SDG&E") Complaints
SDG&E filed five 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.
As previously reported, 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
the Company. 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. There have been no further proceedings and this matter is now
concluded.
58
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 has filed a petition for writ 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.
Nuclear Decommissioning Trust
As previously reported, in 1998, the Company and the trustee of the Company's
master decommissioning trust sued several companies and individuals, in State
District Court in Santa Fe County, for the under-performance of a corporate
owned life insurance program. The program was used to fund a portion of the
Company's nuclear decommissioning obligations for its 10.2% interest in PVNGS.
In August 1999, the Company filed an interlocutory appeal of one of the trial
court's decisions regarding discovery to the New Mexico Court of Appeals. On
June 22, 2000, the Court issued an opinion agreeing with the Company's argument
and reversed the trial court. Subsequently, the parties reached a settlement
agreement under which the complaint and counterclaim were dismissed with
prejudice on September 5, 2000 and the Company and trustee received $13.8
million in settlement proceeds.
59
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
15.0 Letter Re: Unaudited Interim Financial Information
27 Financial Data Schedule
b. Reports on Form 8-K:
Report dated and filed August 18, 2000 reporting PNM plans to buy back $35
million in common stock and PNM proposes settlement of gas rate cases.
Report dated and filed September 6, 2000 reporting the Company's Comparative
Operating Statistics for the months of July 2000 and 1999 and the seven months
ended July 31, 2000 and 1999 to provide investors with key monthly business
indicators.
Report dated and filed September 19, 2000 reporting PNM raised its earnings
estimates for the third quarter, for 2000 and for 2001.
Report dated and filed October 3, 2000 reporting Jeff Sterba, President and
Chief Executive Officer of PNM, has been elected Chairman of the Company's Board
of Directors.
Report dated and filed, October 3, 2000 reporting Jeff Sterba, President and
Chief Executive Officer of PNM, encourages NM regulators to press on toward
Electric Choice.
Report dated and filed, October 3, 2000 reporting the Company's Comparative
Operating Statistics for the months of August 2000 and 1999 and the eight months
ended August 31, 2000 and 1999 to provide investors with key monthly business
indicators.
Report dated and filed, October 16, 2000 reporting the Company's Comparative
Operating Statistics for the months of September 2000 and 1999 and the nine
months ended September 30, 2000 and 1999 to provide investors with key monthly
business indicators.
Report dated and filed, October 16, 2000 announcing PNM hosts third quarter
earnings conference call on the web.
Report dated and filed, October 19, 2000 reporting the Company's Quarter and
Nine Months Ended September 30, 2000 Earnings announcement and the Company's
telephone conference call to discuss the Company's third quarter earnings that
was broadcast.
60
b. Reports on Form 8-K: (continued)
Report dated and filed, October 20, 2000 reporting PNM negotiates cost-saving
revisions to San Juan Coal Contract.
Report dated and filed, October 31, 2000 reporting a slide presentation by the
Company's Chairman, President and Chief Executive Officer, Jeff Sterba, at the
Edison Electric Institute's 35th Annual Financial Conference on Tuesday, October
31, 2000.
61
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW MEXICO
---------------------------------------------
(Registrant)
Date: November 14, 2000 /s/ John R. Loyack
---------------------------------------------
John R. Loyack
Vice President, Corporate Controller
and Chief Accounting Officer
(Officer duly authorized to sign this report)
62