UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITES EXCHANGE ACT OF 1934
For the period ended March 31, 2001
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- 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
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PUBLIC SERVICE COMPANY OF NEW MEXICO
------------------------------------
(Exact name of registrant as specified in its charter)
New Mexico 85-0019030
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(State or other jurisdiction of (I.R.S. Employer
Incorporation of organization) Identification No.)
Alvarado Square, Albuquerque, New Mexico 87158
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(Address of principal executive offices)
(Zip Code)
(505) 241-2700
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(Registrant's telephone number, including area code)
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(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 39,117,799 shares
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Class Outstanding at May 1, 2001
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 Ended March 31, 2001 and 2000...................... 4
Consolidated Balance Sheets -
March 31, 2001 and December 31, 2000............................ 5
Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2001 and 2000...................... 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............................................ 51
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS......................................... 52
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.......................... 54
Signature ....................................................... 56
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
March 31, 2001, and the related condensed consolidated statements of earnings
for the three-month periods ended March 31, 2001 and 2000, and the condensed
consolidated statements of cash flows for the three-month periods ended March
31, 2001 and 2000. These financial statements are the responsibility of the
company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States, the objective
of which is the expression of an opinion regarding the financial statements
taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the financial statements referred to above for them to be in
conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards generally
accepted in the United States, the consolidated balance sheet as of December 31,
2000, 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, 2001, we expressed an unqualified opinion on those
financial statements. In our opinion, the information set forth in the
accompanying condensed consolidated balance sheet as of December 31, 2000 is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
May 9, 2001
3
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended
March 31
---------------------------------
2001 2000
--------------- -------------
(In thousands, except
per share amounts)
Operating Revenues:
Utility................................... $326,459 $220,643
Generation and Trading.................... 491,165 176,298
Unregulated businesses.................... - 349
Intersegment elimination.................. (81,094) (75,999)
--------------- -------------
Total operating revenues................ 736,530 321,291
--------------- -------------
Operating Expenses:
Cost of energy sold....................... 497,098 167,723
Administrative and general................ 39,488 32,196
Energy production costs................... 35,025 35,642
Depreciation and amortization............. 24,219 24,010
Transmission and distribution costs....... 15,277 15,280
Taxes, other than income taxes............ 7,217 7,666
Income taxes.............................. 40,906 7,827
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Total operating expenses................ 659,230 290,344
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Operating income........................ 77,300 30,947
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Other Income and Deductions, Net of Tax 2,634 7,505
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Income before interest charges.......... 79,934 38,452
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Interest Charges:
Interest on long-term debt................ 15,643 15,781
Other interest charges.................... 739 719
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Net interest charges........................ 16,382 16,500
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Net Earnings................................ 63,552 21,952
Preferred Stock Dividend Requirements....... 146 146
--------------- -------------
Net Earnings Applicable to Common Stock..... $ 63,406 $ 21,806
=============== =============
Net Earnings per Common Share:
Basic..................................... $ 1.62 $ 0.55
=============== =============
Diluted................................... $ 1.60 $ 0.55
=============== =============
Dividends Paid per Common Share............. $ 0.20 $ 0.20
=============== =============
The accompanying notes are an integral part of these financial statements.
4
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2001 2000
-------------- --------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service.................................... $2,012,912 $2,030,813
Gas plant in service......................................... 550,744 553,755
Common plant in service and plant held for future use........ 37,002 36,678
-------------- --------------
2,600,658 2,621,246
Less accumulated depreciation and amortization............... 1,175,053 1,153,377
-------------- --------------
1,425,605 1,467,869
Construction work in progress................................ 197,585 123,653
Nuclear fuel, net of accumulated amortization of
$21,734 and $19,081...................................... 24,287 25,784
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Net utility plant.......................................... 1,647,477 1,617,306
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Other Property and Investments:
Other investments............................................ 455,208 479,821
Non-utility property, net of accumulated depreciation of
$1,730 and $1,644........................................ 3,601 3,666
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Total other property and investments....................... 458,809 483,487
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Current Assets:
Cash and cash equivalents.................................... 161,301 107,691
Accounts receivables, net of allowance for uncollectible
accounts of $10,998 and $8,963........................... 276,129 242,742
Other receivables............................................ 45,759 64,857
Inventories.................................................. 35,985 36,091
Regulatory assets............................................ 31,463 47,604
Other current assets......................................... 52,634 11,417
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Total current assets....................................... 603,271 510,402
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Deferred Charges:
Regulatory assets............................................ 227,054 226,849
Prepaid benefit costs........................................ 19,727 18,116
Other deferred charges....................................... 40,716 38,073
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Total current assets....................................... 287,497 283,038
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$ 2,997,054 $ 2,894,233
============== ==============
The accompanying notes are an integral part of these financial statements.
5
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2001 2000
--------------- ---------------
(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands)
Capitalization:
Common stockholders' equity:
Common stock................................................... $ 195,589 $ 195,589
Additional paid-in capital..................................... 431,737 432,222
Accumulated other comprehensive income, net of tax............. 15,372 (27)
Retained earnings.............................................. 360,241 296,843
--------------- ---------------
Total common stockholders' equity........................... 1,002,939 924,627
Minority interest................................................. 11,926 12,211
Cumulative preferred stock without mandatory
redemption requirements...................................... 12,800 12,800
Long-term debt, less current maturities........................... 953,839 953,823
--------------- ---------------
Total capitalization........................................ 1,981,504 1,903,461
--------------- ---------------
Current Liabilities:
Accounts payable.................................................. 217,915 257,991
Accrued interest and taxes........................................ 84,460 36,889
Other current liabilities......................................... 69,036 67,758
--------------- ---------------
Total current liabilities................................... 371,411 362,638
--------------- ---------------
Deferred Credits:
Accumulated deferred income taxes................................... 157,002 166,249
Accumulated deferred investment tax credits......................... 43,834 47,853
Regulatory liabilities.............................................. 64,918 65,552
Regulatory liabilities related to accumulated deferred income tax... 20,696 20,696
Accrued postretirement benefit costs................................ 18,448 11,899
Other deferred credits.............................................. 339,241 315,885
--------------- ---------------
Total deferred credits........................................... 644,139 628,134
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$2,997,054 $2,894,233
=============== ===============
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)
Three Months Ended
March 31,
------------------------------
2001 2000
-------------- --------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings.......................................................... $ 63,552 $ 21,952
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization..................................... 25,080 26,805
Other, net........................................................ 6,462 (3,406)
Changes in certain assets and liabilities:
Accounts receivables............................................ (33,388) 15,022
Other assets.................................................... 23,630 27,342
Accounts payable................................................ (40,075) (61,711)
Accrued taxes................................................... 49,621 4,376
Other liabilities............................................... 14,630 5,198
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Net cash flows provided from operating activities............... 109,512 35,578
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Cash Flows Used for Investing Activities:
Utility plant additions............................................... (55,820) (22,361)
Return on PVNGS lease obligation bonds................................ 8,535 8,636
Other investing....................................................... 109 (3,155)
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Net cash flows used for investing activities.................... (47,176) (16,880)
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Cash Flows Used for Financing Activities:
Repayments............................................................ - (32,800)
Common stock repurchase............................................... - (18,854)
Exercise of employee stock options.................................... (476) -
Dividends paid........................................................ (7,965) (8,182)
Other financing....................................................... (285) (288)
-------------- --------------
Net cash flows used for financing activities.................... (8,726) (60,124)
-------------- --------------
Increase (Decrease) in Cash and Cash Equivalents........................ 53,610 (41,426)
Beginning of Period..................................................... 107,691 120,399
-------------- --------------
End of Period........................................................... $161,301 $ 78,973
============== ==============
Supplemental Cash Flow Disclosures:
Interest paid......................................................... $ 17,748 $ 20,318
============== ==============
Income taxes paid, net ............................................... $ 3,400 $ 23
============== ==============
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 March 31, 2001 and December
31, 2000, the consolidated results of its operations for the three months ended
March 31, 2001 and 2000 and the consolidated statements of cash flows for the
three months ended March 31, 2001 and 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, 2000, which are included on the
Company's Annual Report on Form 10-K for the year ended December 31, 2000. The
results of operations presented in the accompanying financial statements are not
necessarily representative of operations for an entire year.
Certain amounts in the 2000 consolidated financial statements and notes
have been reclassified to conform to the 2001 financial statement presentation.
(2) Nature of Business and Segment Information
The Company is an investor-owned integrated utility engaged in the
generation, transmission, distribution and sale and trading of electricity, and
the transportation, distribution and sale of natural gas. In addition, the
Company provides energy and utility related services under its wholly-owned
subsidiary, Avistar, Inc. ("Avistar").
The Company's principal business segments are Utility Operations, which
include the Electric Product Offering ("Electric") and the Natural Gas Product
Offering ("Gas"), and Generation and Trading Operations ("Generation"). The
Electric Product Offering consists of two major business lines that include
distribution and transmission. The transmission business line does not meet the
definition of a segment due to its immateriality and is combined with the
distribution business line for disclosure purposes.
Electric procures all of its electric power needs from the Company's
Generation and Trading Operations. These intersegment sales are priced using
internally developed transfer pricing, and are not based on market rates.
Customer electric rates are regulated by the New Mexico Public Regulation
Commission ("PRC") and determined on a basis that includes the recovery of the
cost of power production by the Company's Generation and Trading Operations and
a return on the related assets, among other things.
8
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(2) Nature of Business and Segment Information (Continued)
UTILITY OPERATIONS
Electric
The Company provides jurisdictional retail electric service to a large
area of north central New Mexico, including the cities of Albuquerque and Santa
Fe, and certain other areas of New Mexico. The Company owns or leases 2,781
circuit miles of transmission lines, interconnected with other utilities east
into Texas, west into Arizona, and north into Colorado and Utah.
Gas
The Company's gas operations distribute natural gas to most of the
major communities in New Mexico, including Albuquerque and Santa Fe. The
Company's customer base includes both sales-service customers and
transportation-service customers.
The Company obtains its supply of natural gas primarily from sources
within New Mexico pursuant to contracts with producers and marketers.
GENERATION AND TRADING OPERATIONS
The Company's generation and trading operations serve four principal
markets. These include sales to the Company's Utility Operations to cover
jurisdictional electric demand, sales to firm-requirements wholesale customers,
other contracted sales to third parties for a specified amount of capacity
(measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a
given period of time and energy sales made on an hourly basis at fluctuating,
spot-market rates. These latter two markets constitute the Company's power
trading operations. As of March 31, 2001 the total net generation capacity of
facilities owned or leased by the Company was 1,653 MW, including a 132 MW power
purchase contract accounted for as an operating lease. In addition to generation
capacity the Company purchases power in open market.
UNREGULATED
The Company's wholly-owned subsidiary, Avistar, was formed in August
1999 as a New Mexico corporation and is currently engaged in certain
unregulated, non-utility businesses, including energy and utility-related
services previously operated by the Company. Unregulated also includes certain
corporate activities, which are not material.
REGULATION AND RESTRUCTURING
In April 1999, New Mexico's Electric Utility Industry Restructuring Act
of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act
opens the state's electric power market to customer choice. In March 2001,
amendments to the Restructuring Act were passed which delays the original
implementation dates by approximately five years, including the requirement for
corporate separation of certain deregulated activities from activities
9
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(2) Nature of Business and Segment Information (Continued)
regulated by the PRC. In addition, the PRC will have the authority to delay
implementation for another year under certain circumstances. The Restructuring
Act, as amended, will give schools, residential and small business customers the
opportunity to choose among competing power suppliers beginning in January 2007.
Competition would be expanded to include all customers starting in July 2007.
The amendments require that the PRC approve a holding company, subject
to terms and conditions in the public interest, without corporate separation of
the regulated and deregulated activities, by July 1, 2001. In April 2001, the
Company filed its application for the creation of a holding company. Hearings on
the matter began May 10, 2001. The Company is unable to predict what terms and
conditions may be imposed as part of the approval process. Previously, in June
2000, shareholders approved the mandatory share exchange necessary to implement
a holding company structure. In April 2001, the Company's Board of Directors
amended the articles of incorporation of the proposed holding company to rename
the holding company "PNM Resources, Inc." (PNM Resources). The holding company
was originally approved by shareholders last year as Manzano Corporation. The
Company is unable to predict the outcome of its application and whether or not
the holding company proposal will be approved by the PRC with acceptable
conditions.
In addition, the amendments allow utilities to engage in unregulated
power generation business activities until corporate separation is implemented.
The Company believes that its ability to form a new holding company and expand
generation assets in an unregulated environment will give it the flexibility it
needs to pursue its strategic plan despite the delay in customer choice and
corporate separation. The Company is unable to predict the form its
restructuring will take under the delayed implementation of customer choice. The
formulation of a restructuring plan will be dependent on future business
conditions at the expected time customer choice is implemented (See "Other
Issues Facing The Company - Recovery of Certain Costs Under The Restructuring
Act" below).
RISKS AND UNCERTAINTIES
The Company's future results may be affected by changes in regional
economic conditions; fluctuations in fuel, purchased power and gas prices; the
actions of utility regulatory commissions; changes in law; environmental
regulations and external factors such as the weather. As a result of State and
Federal regulatory reforms, the public utility industry is undergoing a
fundamental change. As this occurs, the electric generation business is
transforming into a competitive marketplace. In turn, these reforms are being
revisited as a result of the energy crisis in California, escalating prices for
power elsewhere in the Western United States, and concerns over inadequate
capacity, among other conditions. The Company's future results will be impacted
by its ability to recover its stranded costs, the market price of electricity
and natural gas costs incurred previously in providing power generation to
electric service customers, the costs of transition to an unregulated status,
future regulatory actions, and the price of power in the wholesale markets. In
addition, as a result of deregulation, the Company may face competition from
companies with greater financial and other resources.
10
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(2) Nature of Business and Segment Information (Continued)
Summarized financial information by business segment for the three
months ended March 31, 2001 and 2000 is as follows:
Utility
------------------------------------
Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2001:
Operating revenues:
External customers............ $134,346 $191,936 $326,282 $410,248 $ - $736,530
Intersegment revenues......... 177 - 177 80,917 - 81,094
Depreciation and amortization.... 8,025 5,290 13,315 10,895 9 24,219
Interest income.................. 457 286 743 12,625 1,831 15,199
Net interest charges............. 4,273 2,986 7,259 9,095 28 16,382
Income tax expense (benefit)
From continuing operations..... 7,699 5,682 13,381 35,772 (6,521) 42,632
Operating income (loss).......... 15,793 11,387 27,180 59,027 (8,907) 77,300
Segment net income (loss)........ 11,749 8,671 20,420 54,587 (11,455) 63,552
Total assets..................... 724,513 517,412 1,241,925 1,538,209 216,920 2,997,054
Gross property additions......... 11,440 6,574 18,014 36,342 1,464 55,820
2000:
Operating revenues:
External customers............ $125,922 $ 94,545 $220,467 $100,475 $ 349 $321,291
Intersegment revenues......... 177 - 177 75,822 - 75,999
Depreciation and amortization.... 8,326 5,366 13,692 10,312 6 24,010
Interest income.................. 46 136 182 9,779 1,304 11,265
Net interest charges............. 4,471 2,854 7,325 9,016 159 16,500
Income tax expense (benefit)
from continuing operations..... 5,996 3,726 9,722 5,720 (2,741) 12,701
Operating income (loss).......... 13,892 8,118 22,010 13,836 (4,899) 30,947
Segment net income (loss)........ 9,266 5,500 14,766 11,370 (4,184) 21,952
Total assets..................... 774,300 454,224 1,228,524 1,374,329 23,444 2,626,297
Gross property additions......... 9,846 4,737 14,583 7,778 - 22,361
11
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(3) Comprehensive Income
Changes in comprehensive income are as follows:
Three Months Ended
March 31
-------------------------
2001 2000
----------- ------------
(In thousands)
Net Earnings.................................................................... $63,552 $21,952
----------- ------------
Other Comprehensive Income, net of tax: Unrealized gain (loss) on securities:
Unrealized holding gains (losses) arising during the period............... (948) 1,475
Less: reclassification adjustment for gains included
in net income........................................................... (296) (1,499)
Minimum pension liability adjustment......................................... 780 -
Mark-to-market adjustment for certain derivative
transactions (see Footnote 4):
Initial implementation of SFAS 133 designated cash flow
hedges............................................................... 6,148 -
Change in fair market value of designated
cash flow hedges..................................................... 9,715 -
----------- ------------
Total Other Comprehensive Income (Loss)...................................... 15,399 (24)
----------- ------------
Total Comprehensive Income...................................................... $78,951 $21,928
=========== ============
The Company's investments held in grantor trusts for nuclear
decommissioning and certain retirement benefits are classified as
available-for-sale, and accordingly unrealized holding gains and losses are
recognized as a component of comprehensive income. Realized gains and losses are
included in earnings. Net losses to the Company's pension plans not yet
recognized as net periodic pension costs (or additional minimum liability) are
reported as a component of comprehensive income. Changes in the liability are
adjusted as necessary. 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 implemented Statement of Financial Accounting Standards No.
133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"),
as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and
reporting standards requiring derivative instruments to be recorded in the
balance sheet as either an asset or liability measured at their fair value. SFAS
133, as amended, also requires that changes in the derivatives' fair value be
recognized currently in earnings unless specific hedge accounting or normal
purchase and sale 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
12
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4) Financial Instruments (Continued)
of transactions that receive hedge accounting. SFAS 133, as amended, provides
that the effective portion of the gain or loss on a derivative instrument
designated and qualifying as a cash flow hedging instrument be reported as a
component of other comprehensive income and be reclassified into earnings in the
same period or periods during which the hedged forecasted transaction affects
earnings. The results of hedge ineffectiveness and the change in fair value of a
derivative that an entity has chosen to exclude from hedge effectiveness are
required to be presented in current earnings.
The Company uses derivative financial instruments to manage risk as it
relates to changes in natural gas and electric prices and adverse market changes
for investments held by the Company's various trusts. The Company also uses
certain derivative instruments for bulk power electricity trading purposes in
order to take advantage of favorable price movements and market timing
activities in the wholesale power markets.
The Company is exposed to credit losses in the event of non-performance
or non-payment by counterparties. The Company uses a credit management process
to assess and monitor the financial conditions of counterparties. The Company's
credit risk with its largest counterparty as of March 31, 2001 was $20.2
million.
Natural Gas Contracts
Utility Operations
Pursuant to a 1997 order issued by the New Mexico Public Utility
Commission ("NMPUC"), predecessor to the PRC, the Company's utility operations
have previously and continue to enter 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 impacts 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 are not affected by the gains or
losses generated by these instruments. 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.
The Company expended $5 million to purchase physical options that limit the
maximum amount the Company would pay for gas during the winter heating season.
The Company recovered 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. Results of the winter 2000-2001 hedging activities were an estimated $27
million benefit to system gas supply customers in the form of lower gas costs
net of the cost of the price caps. As of March 31, 2001, all gas option
contracts were closed.
Generation and Trading Operations
The Company's Generation and Trading Operations conduct a hedging
program to reduce its exposure to fluctuations in prices for natural gas used as
a fuel source for some of its generation. In the first quarter of 2001, the
Generation Operations purchased futures contracts
13
(4) Financial Instruments (Continued)
for a portion of its anticipated natural gas needs in the second, third and
fourth quarters. The futures contracts lock-in the Company's natural gas
purchase prices at $5.37 to $6.40 per MMBTU and have a notional principal of
$20.9 million. Simultaneously, a delivery location basis swap was purchased for
quantities corresponding to the futures quantities to protect against price
differential changes at the specific delivery points. The Company is accounting
for these transactions as cash flow hedges; accordingly, gains and losses
related to these transactions are deferred and recorded as a component of Other
Comprehensive Income. These gains and losses are reclassified and recognized in
earnings as an adjustment to the Company's cost of fuel when the hedged
forecasted transaction effects earnings. The assessment of hedge effectiveness
is based on the changes in the futures contract price as adjusted for the
delivery point basis swap. There was no hedge ineffectiveness recognized in the
three months ended March 31, 2001.
Electricity 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. 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. As a result, these contracts are marked to market at the end of
each period. The related gains and losses for these derivative instruments are
recorded as adjustments to operating revenues.
Through March 31, 2001, the Company's wholesale electric trading
operations settled trading contracts for the sale of electricity that generated
$11.8 million of electric revenues by delivering 122 million KWh. The Company
purchased $10.9 million or 102 million KWh of electricity to support these
contractual sales and other open market sales opportunities.
As of March 31, 2001, the Company had open trading contract positions
to buy $77.2 million and to sell $35.7 million of electricity. At March 31,
2001, the Company had a gross mark-to-market gain (asset position) on these
trading contracts of $14.4 million and a gross mark-to-market loss (liability
position) of $17.9 million, with net mark-to-market losses of $3.5 million. The
mark-to-market valuation is recognized in earnings each period.
In addition, the Company enters into forward physical contracts. The
Company generally accounts for these derivative financial instruments as normal
sales and purchases as defined by SFAS 133, as amended. These contracts are
typically sales of the Company's electric capacity in excess of its
jurisdictional needs, including reserves, or purchases of jurisdictional needs,
including reserves, when resource shortfalls exist. The Company from time to
time makes forward purchases to serve its jurisdictional needs when the cost of
purchased power is less than the incremental cost of its generation. At March
31, 2001, the Company had open forward positions classified as normal sales of
electricity of $383.8 million and normal purchases of electricity of $221.7
million.
14
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4) Financial Instruments (Continued)
The Company designated certain forward purchase contracts for
electricity as cash flow hedges. The Company's designated cash flow hedges at
March 31, 2001, were forward purchase contracts for the purchase of electric
power for forecasted jurisdictional use during planned outages in 2001 and
certain forecasted sales. The hedged risks associated with these instruments are
the changes in cash flows related to forecasted purchase of electricity due to
changes in the price of electricity on the spot market. Assessment of hedge
effectiveness will be based on the changes in the forward price of electricity.
There was no hedge ineffectiveness recognized in the three months ended March
31, 2001.
It is a common practice within the electric utility industry to net
offsetting purchase and sales contracts between two or more counterparties to
facilitate transmission. This is commonly referred to as a "book-out." Whether a
book-out occurs is dependant on a number of factors, including agreement by all
parties in the chain of the transaction, efficiency of the transaction flow,
congestion on the electrical transmission system, and system reliability issues.
Book-outs do not occur until a short time before the electricity is due to be
physically delivered, no matter when the original contracts in the chain were
entered into, and have no legal standing should one of the parties in the chain
default. The Derivatives Implementation Group ("DIG") of the FASB has reached a
tentative conclusion that all contracts for the sale or purchase of electricity
that are subject to being booked out, whether that is the intent of the
counterparties or not, do not qualify for the normal sale or normal purchase
exception. The conclusion is tentative until formally cleared by the FASB and
incorporated in an FASB staff implementation guide. If the conclusion of the DIG
is accepted by the FASB, the Company may be required to mark-to-market its
transactions that it has classified as normal purchases and normal sales. The
Company is unable to determine the impact of this conclusion.
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
In February 2001, the Company terminated certain financial derivatives
based on the Standard & Poor's ("S&P") 500 Index. These instruments were used to
limit potential loss on investments for nuclear decommissioning, executive
retirement and retiree medical benefits due to adverse market fluctuations. The
Company recognized a realized gain of $0.5 million (pretax) as a result.
Previously, the Company had marked-to-market the financial instruments to match
the hedged investment activity.
15
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 March 31 (in thousands except per share amounts):
Three Months Ended
March 31,
2001 2000
----------- -----------
Basic:
Net Earnings from Continuing Operations............... $ 63,552 $ 21,952
----------- -----------
Net Earnings.......................................... 63,552 21,952
Preferred Stock Dividend Requirements................. 146 146
----------- -----------
Net Earnings Applicable to Common Stock............... $ 63,406 $ 21,806
=========== ===========
Average Number of Common Shares Outstanding........... 39,118 39,973
=========== ===========
Net Earnings per Common Share (Basic)................. $ 1.62 $ 0.55
=========== ===========
Diluted:
Net Earnings Applicable to Common Stock
Used in basic calculation........................... $ 63,406 $ 21,806
=========== ===========
Average Number of Common Shares Outstanding........... 39,118 39,973
Diluted effect of common stock equivalents (a)........ 481 29
----------- -----------
Average common and common equivalent shares
Outstanding......................................... 39,599 40,002
=========== ===========
Net Earnings per Share of Common Stock (Diluted)...... $ 1.60 $ 0.55
=========== ===========
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out-of-the-money options of 186,736 for the three months ended
March 31, 2000. There were no anti-dilutive common stock equivalents in
2001.
(6) Commitments and Contingencies
Construction Commitment
The Company has committed to purchase combustion turbines for $126
million. The turbines are for planned power generation plants with an estimated
cost of approximately $245 million for which contracts have not been finalized.
The planned plants are part of the Company's ongoing competitive strategy of
increasing generation capacity over time.
16
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies (Continued)
Natural Gas Explosion
On April 25, 2001, a natural gas explosion occurred in Santa Fe, New
Mexico. The apparent cause of the explosion was a leak from a Company line near
the location. The explosion destroyed a small building and injured two persons
who were working in the building. At least one passerby received minor injuries
from the blast. Several claims for property and business interruption damages
have been received by the Company. The cause of the leak is unknown and the
Company is conducting an investigation into the explosion. No lawsuits against
the Company have yet been served on the Company. At this time, the Company is
unable to estimate the potential liability, if any, that the Company may incur.
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.
Implementation of 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 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. The Company continued its analysis
and collection efforts of its delinquent accounts resulting from the problems
associated with the implementation of the new customer billing system throughout
2000 and identified additional bad debt exposure. As a result, the Company
significantly increased its estimated bad debt costs throughout 1999 and 2000.
By the end of 2000, the Company completed its analysis of its
delinquent accounts and resumed its normal collection procedures. As a result,
the Company determined that $13.5 million of customer receivables would not be
collectible. Based upon information available at March 31, 2001, the Company
believes the allowance for doubtful accounts of $11.0 million is adequate for
management's estimate of potential uncollectible accounts.
In addition, due to the significantly higher natural gas prices
experienced in November and December 2000, the Company increased its bad debt
expense by approximately $1 million for the three months ended March 31, 2001
and $2 million for the year ended December 31, 2000 in anticipation of higher
than normal delinquency rates. The Company expects this trend to continue as
long as natural gas prices remain higher than historical levels.
17
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies (Continued)
The following is a summary of the allowance for doubtful accounts
during the three months ended March 31, 2001 and the year ended December 31,
2000:
March 31, December 31,
2001 2000
--------------- ---------------
Allowance for doubtful accounts, beginning
of year................................................... $ 8,963 $12,504
Bad debt expense............................................ 3,434 9,980
Less: Write off (adjustments) of uncollectible accounts.... 1,399 13,521
------------- --------------
Allowance for doubtful accounts, end of year ............... $10,998 $ 8,963
============= ==============
PVNGS Liability and Insurance Matters
The PVNGS participants have insurance for public liability resulting
from nuclear energy hazards to the full limit of liability under Federal law.
This potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $200 million and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the primary liability insurance
limit, the Company could be assessed retrospective adjustments. The maximum
assessment per reactor under the program for each nuclear incident is
approximately $88 million, subject to an annual limit of $10 million per reactor
per incident. Based upon the Company's 10.2% interest in the three PVNGS units,
the Company's maximum potential assessment per incident for all three units is
approximately $27.0 million, with an annual payment limitation of $3 million per
incident. If the funds provided by this retrospective assessment program prove
to be insufficient, Congress could impose revenue raising measures on the
nuclear industry to pay claims. The United States Nuclear Regulatory Commission
and Congress are reviewing the related laws. The Company cannot predict whether
or not Congress will change the law. However, certain changes could possibly
trigger "Deemed Loss Events" under the Company's PVNGS leases, absent waiver by
the lessors.
The PVNGS participants maintain "all-risk" (including nuclear hazards)
insurance for nuclear property damage to, and decontamination of, property at
PVNGS in the aggregate amount of $2.75 billion as of January 1, 2001. The
Company is a member of an industry mutual insurer which provides both the
"all-risk" and increased cost of generation insurance to the Company. In the
event of adverse losses experienced by this insurer, the Company is subject to
an assessment. The Company's maximum share of any assessment is approximately
$2.3 million per year.
PVNGS Decommissioning Funding
The Company has a program for funding its share of decommissioning
costs for PVNGS. The nuclear decommissioning funding program is invested in
equities and fixed income instruments in qualified and non-qualified trusts. The
results of the 1998 decommissioning cost study indicated that the Company's
share of the PVNGS
18
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Commitments and Contingencies (continued)
decommissioning costs excluding spent fuel disposal will be approximately $179.9
million (in 2001 dollars). The estimated market value of the trusts at the end
of March 31, 2001 was approximately $51 million.
Nuclear Spent Fuel and Waste Disposal
Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987
(the "Waste Act"), the United States Department of Energy ("DOE") is obligated
to accept and dispose of all spent nuclear fuel and other high-level radioactive
wastes generated by all domestic power reactors. Under the Waste Act, DOE was to
develop the facilities necessary for the storage and disposal of spent nuclear
fuel and to have the first such facility in operation by 1998. DOE has announced
that such a repository now cannot be completed before 2010.
The operator of PVNGS has capacity in existing fuel storage pools at
PVNGS which, with certain modifications, could accommodate all fuel expected to
be discharged from normal operation of PVNGS through 2002, and believes it could
augment that storage with the new facilities for on-site dry storage of spent
fuel for an indeterminate period of operation beyond 2002, subject to obtaining
any required governmental approvals. The Company currently estimates that it
will incur approximately $41 million (in 1998 dollars) over the life of PVNGS
for its share of the fuel costs related to the on-site interim storage of spent
nuclear fuel during the operating life of the plant. The Company accrues these
costs as a component of fuel expense, meaning the charges are accrued as the
fuel is burned. The operator of PVNGS currently believes that spent fuel storage
or disposal methods will be available for use by PVNGS to allow its continued
operation beyond 2002.
Other
There are various claims and lawsuits pending against the Company and
certain of its subsidiaries. The Company is also subject to Federal, state and
local environmental laws and regulations, and is currently participating in the
investigation and remediation of numerous sites. In addition, the Company
periodically enters into financial commitments in connection with business
operations. It is not possible at this time for the Company to determine fully
the effect of all litigation on its consolidated financial statements. However,
the Company has recorded a liability where the litigation effects can be
estimated and where an outcome is considered probable. The Company does not
expect that any known lawsuits, environmental costs and commitments will have a
material adverse effect on its financial condition or results of operations.
(7) Environmental Issues
The normal course of operations of the Company necessarily involves
activities and substances that expose the Company to potential liabilities under
laws and regulations protecting the environment. Liabilities under these laws
and regulations can be material and in some instances may be imposed without
regard to fault, or may be imposed for past acts, even though the past acts may
have been lawful at the time they occurred. Sources of potential
19
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(7) Environmental Issues (Continued)
environmental liabilities include the Federal Comprehensive Environmental
Response Compensation and Liability Act of 1980 and other similar statutes.
The Company records its environmental liabilities when site assessments
or remedial actions are probable and a range of reasonably likely cleanup costs
can be estimated. The Company reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified
site using currently available information, including existing technology,
presently enacted laws and regulations, experience gained at similar sites, and
the probable level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless
there is a probable amount, the Company, records the lower end of this
reasonably likely range of costs (classified as other long-term liabilities at
undiscounted amounts).
The Company's recorded estimated minimum liability to remediate its
identified sites is $6.8 million. The ultimate cost to clean up the Company's
identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: the extent and nature
of contamination; the scarcity of reliable data for identified sites; and the
time periods over which site remediation is expected to occur. The Company
believes that, due to these uncertainties, it is remotely possible that cleanup
costs could exceed its recorded liability by up to $11.6 million. The upper
limit of this range of costs was estimated using assumptions least favorable to
the Company.
In 2001, the Company anticipates spending $1.4 million for remediation
and $0.7 million for control and prevention. The majority of the March 31, 2001
environmental liability is expected to be paid over the next five years, funded
by cash generated from operations. Future environmental obligations are not
expected to have a material impact on the results of operations or financial
condition of the Company.
(8) Proposed Acquisition
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, prior to the acquisition of Western's utility businesses by the
Company.
20
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(8) Proposed Acquisition (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 94 million shares
outstanding, of which approximately 41 percent will be owned by former Company
shareholders and 59 percent will be owned by former Western Resources
shareholders and Westar Industries.
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. Under the terms of the acquisition
agreement, Western Resources and Westar have been given an incentive to reduce
Western Resources net debt balance prior to the consummation of the transaction
by selling non-utility assets or through other debt reduction activities. The
agreement contains a mechanism to adjust the transaction consideration based on
certain activities not affecting the utility operations, which increase the
equity of the utility. In addition, Westar Industries has the option of making
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. The effect of these 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 February 2001, Westar purchased 14.4 million Western Resources
common shares at $24.358 per share (based on a 20 day look-back price at
February 28, 2001) at an aggregate price of $350 million. As a result of this
equity contribution, the acquisition consideration may be adjusted to include an
additional 4.3 million shares of the new holding company depending on the impact
of future transactions between Western Resources and Westar.
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.
Based on the volume weighted average closing price of the Company's
common stock over the two days prior and two days subsequent to the announcement
of the transaction of $24.149 per share, the indicated equity consideration of
the transaction was approximately $945 million, excluding the potential issuance
of additional shares discussed above. There is approximately $2.9 billion of
existing Western Resources debt giving the transaction an aggregate enterprise
value of approximately $3.8 billion. There are plans for the new holding company
to reduce and refinance a portion of the Western Resources debt.
21
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(8) Proposed Acquisition (Continued)
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 ("KCC"), the PRC, the Federal Energy Regulatory Commission, the
Nuclear Regulatory Commission, the Federal Communications Commission and either
the Federal Trade Commission or the Department of Justice under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976. In addition, an adverse
regulatory outcome related to other actions involving rate making or approval of
regulatory plans may affect the transaction. 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. Management believes that the
above mentioned approvals are expected to be obtained over the next 12 to 15
months, however should such approvals not be obtained, final consummation of the
proposed acquisition cannot occur.
(9) 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.
22
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
All references to the Company refer to Public Service Company of New
Mexico or its proposed successor holding company PNM Resources, Inc. (see
"Restructuring the Electric Utility Industry" below).
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 I, Item 3. - 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 product offerings through its wholly-owned subsidiary,
Avistar. As it currently operates, the Company's principal business segments are
Utility Operations, which include the Electric Product Offering ("Electric") and
the Natural Gas Product Offering ("Gas"), and Generation and Trading Operations
("Generation and Trading"). The Electric Product Offering consists of two major
business lines that include distribution and transmission. The transmission
business line does not meet the definition of a segment for accounting purposes
due to its immateriality, and for purposes of this discussion, it is combined
with the distribution product offering.
UTILITY OPERATIONS
Electric
The Company provides jurisdictional retail electric service to a large
area of north central New Mexico, including the City of Albuquerque and the City
of Santa Fe, and certain other areas of New Mexico. Retail sale revenues, which
include distribution and transmission, were $134.5 million and $126.1 million
for the three months ended March 31, 2001 and March 31, 2000 respectively.
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.
23
Gas
The Company's Gas operations distribute natural gas to most of the
major communities in New Mexico, including Albuquerque and Santa Fe. The
Company's gas 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, provide the Company with cost-of-service revenues only.
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 peak-day demand.
The following table shows gas throughput by customer class:
GAS THROUGHPUT
(Thousands of decatherms)
Three Months Ended
March 31,
2001 2000
---------- -----------
Residential............................ 12,481 11,121
Commercial............................. 4,207 3,477
Industrial............................. 1,980 224
Transportation*........................ 9,178 9,011
Other.................................. 1,667 1,932
---------- -----------
29,513 25,765
========== ===========
The following table shows gas revenues by customer:
GAS REVENUES
(Thousands of dollars)
Three Months Ended
March 31,
2001 2000
------------ ------------
Residential........................... $121,590 $62,851
Commercial............................ 36,798 16,615
Industrial............................ 13,537 794
Transportation*....................... 4,002 3,984
Other................................. 16,009 10,301
------------ ------------
$191,936 $94,545
============ ============
*Customer-owned gas.
24
GENERATION AND TRADING OPERATIONS
The Company's Generation and Trading 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. The
third market consists of other contracted sales to third parties for which the
Generation and Trading Operations commit 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.
Off-system sales include the Company's energy trading activities.
The following table shows sales by customer class:
GENERATION AND TRADING SALES BY MARKET
(Megawatt hours)
Three Months Ended
March 31,
2001 2000
--------------- ----------------
Intersegment sales...................... 1,718,565 1,655,150
Firm-requirements wholesale............. 122,786 47,921
Other contracted off-system sales....... 1,901,261 2,042,998
Economy energy sales.................... 1,134,084 1,272,668
--------------- ----------------
4,876,696 5,018,737
=============== ================
The following table shows revenues by customer class:
GENERATION AND TRADING REVENUES BY MARKET
(Thousands of dollars)
Three Months Ended
March 31,
2001 2000
--------------- ----------------
Intersegment revenues................... $ 80,917 $ 75,822
Firm-requirements wholesale............. 3,128 1,736
Other contracted off-system revenues.... 197,892 62,807
Economy energy revenues................. 209,641 35,714
Other................................... (413) 219
--------------- ----------------
$ 491,165 $ 176,298
=============== ================
The Generation and Trading Operations have ownership interests in
certain generating facilities located in New Mexico, including the San Juan
Generating Station, a coal fired unit, and the Four Corners Power Plant, 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
25
Generation and Trading Operations also own Reeves Generating Station, a gas and
oil fired unit and Las Vegas Generating Station, a gas and oil fired unit, that
are used for reliability purposes or to generate electricity for the wholesale
market during certain demand periods in the Generation and Trading Operations'
wholesale power markets.
As of December 31, 2000, the total net generation capacity of
facilities owned or leased by the Generation and Trading Operations was 1,653
MW. On July 13, 2000, the Company commenced a 20 year power purchase agreement
for an additional 132 MW for the rights to all output of a new gas fired
generating plant. In addition to its generation capacity, the Generation and
Trading Operations purchase power in the open market.
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 $50 million in equity in Avistar and to enter into a reciprocal loan
agreement for up to $30 million. The Company has currently invested $35 million
in Avistar.
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.
The new combined company will serve over one million retail electric
customers and 435,000 retail gas customers in New Mexico and Kansas and will
have generating capacity of more than 7,000 MW. 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. However, the Company intends to
proceed with plans to add generation capacity to serve Western wholesale
markets. The transaction will also make the new company a leading energy
supplier in the Western and Midwestern wholesale markets.
The transaction will provide the Company with the opportunity to
accelerate its proven growth strategy by developing a similar niche product,
asset-backed wholesale power marketing strategy at Western Resources. The
strategic nature of the acquisition is based upon revenue-growth. As a result,
the Company expects modest cost savings although cost reduction will be one
aspect of the integration effort. At present the Company does not anticipate
significant cost savings as a result of involuntary workforce reductions. 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.
The transaction is expected to close promptly after all of the
conditions to its consummation are fulfilled, including the spin off to Western
Resources' shareholders of Western Resources' non-utility businesses, approval
from both companies' shareholders and customary regulatory approvals. (See
"Other Issues Facing The Company - Acquisition of Western Resources Electric
Operations" below).
26
RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY
In April 1999, New Mexico's Electric Utility Industry Restructuring Act
of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act
opens the state's electric power market to customer choice. In March 2001,
amendments to the Restructuring Act were passed which delay the original
implementation dates by approximately five years, including the requirement for
corporate separation of certain deregulated activities from activities regulated
by the PRC. In addition, the PRC will have the authority to delay implementation
for another year under certain circumstances. The Restructuring Act, as amended,
will give schools, residential and small business customers the opportunity to
choose among competing power suppliers beginning in January 2007. Competition
would be expanded to include all customers starting in July 2007.
The amendments require that the PRC approve a holding company, subject
to terms and conditions in the public interest, without corporate separation of
the regulated and deregulated activities, by July 1, 2001. In April 2001, the
Company filed its application for the creation of a holding company. Hearings on
the matter occurred in mid May. Previously, in June 2000, shareholders approved
the mandatory share exchange necessary to implement a holding company structure.
In April 2001, the Company's Board of Directors amended the articles of
incorporation of the proposed holding company to rename the holding company "PNM
Resources, Inc." (PNM Resources). The holding company was originally approved by
shareholders last year as Manzano Corporation. The Company is unable to predict
the outcome of its application and whether or not the holding company proposed
will be approved by the PRC with acceptable conditions.
In addition, the amendments to the Restructuring Act allow utilities to
engage in unregulated power generation business activities until corporate
separation is implemented. The Company believes that its ability to form a new
holding company and expand generation assets in an unregulated environment will
give it the flexibility it needs to pursue its strategic plan despite the delay
in customer choice and corporate separation. The Company is unable to predict
the form its restructuring will take under the delayed implementation of
customer choice. The formulation of a restructuring plan will be dependent on
future business conditions at the expected time customer choice is implemented
(See "Other Issues Facing The Company - Recovery of Certain Costs Under The
Restructuring Act" below).
COMPETITIVE STRATEGY
The Restructuring Act, as amended, allows the Company and other
utilities to build or acquire new generating plants for merchant purposes in the
interim with minimum regulatory approvals. These new plants will be excluded
from utility rates under the provisions of the bill. The cost of new unregulated
utility generation resources will serve as a cap for ratemaking purposes, or the
price of new resources needed to serve retail customers until customer choice
and corporate restructuring is implemented. In addition, the New Mexico
Legislature passed and the Governor signed, an amendment to the Public Utility
Act requiring the PRC to act on siting applications for certain generating
plants and transmission lines within six months. Transmission applications that
are environmentally sensitive would be allowed an additional ten months.
27
The Company's Generation and Trading Operations have contributed
significant earnings to the Company in recent years as a result of increased
off-system sales including its energy trading activities. The Company plans to
expand its wholesale energy trading functions which could include an expansion
of its generation portfolio as well as expanding trading operations. 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 energy trading activities, the
Company will further focus on opportunities in the market place 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, excluding the effects of the Western
Resources transaction, through the construction or acquisition of additional
power generation assets in its surrounding region of operations over the next
five to seven years. The Company will continue to pursue growth in its
generation portfolio and intends to spend approximately $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. The Company currently has $161.3 million of available cash as well as
adequate borrowing capacity to fund the expansion program. There can be no
assurance that investments in new unregulated generation facilities, 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. Recent federal actions have
focused on the energy crisis in California with bills being introduced to
require caps on wholesale prices. In addition, the Senate Banking Committee has
voted 19-1 to repeal the Public Utility Holding Company Act.
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.
28
RESULTS OF OPERATIONS
The following discussion is based on the financial information
presented in Footnote 1 of the Consolidated Financial Statements - Nature of
Business and Segment Information. The table below sets forth the operating
results as percentages of total operating revenues for each business segment.
Three Months Ended March 31, 2001
Utility
--------------------------------------------------- Generation
Electric Gas and Trading
------------------------- ------------------------ ---------------
Operating revenues:
External customers................... $134,346 99.87% $191,936 100.00% $410,248 83.53%
Intersegment revenues................ 177 0.13 - 0.00 80,917 16.47
----------- ---------- ----------- --------- ---------- ---------
Total revenues....................... 134,523 100.00 191,936 100.00 491,165 100.00
----------- ---------- ----------- --------- ---------- ---------
Cost of energy sold.................... 1,560 1.16 148,472 77.35 347,066 70.66
Intersegment purchases................. 80,917 60.15 - 0.00 177 0.04
----------- ---------- ----------- --------- ---------- ---------
Total fuel costs..................... 82,477 61.31 148,472 77.35 347,243 70.70
----------- ---------- ----------- --------- ---------- ---------
Gross margin........................... 52,046 38.69 43,464 22.65 143,922 29.30
----------- ---------- ----------- --------- ---------- ---------
Administrative and other costs......... 9,735 7.24 12,199 6.36 4,960 1.01
Energy production costs................ 310 0.23 431 0.22 34,284 6.98
Depreciation and amortization.......... 8,025 5.97 5,290 2.76 10,895 2.22
Transmission and distribution costs.... 8,107 6.03 7,056 3.68 113 0.02
Taxes other than income taxes.......... 2,527 1.88 1,596 0.83 1,921 0.39
Income taxes........................... 7,549 5.61 5,505 2.87 32,722 6.66
----------- ---------- ----------- --------- ---------- ---------
Total non-fuel operating expenses.... $36,253 26.95 $32,077 16.71 $84,895 17.28
----------- ---------- ----------- --------- ---------- ---------
Operating income....................... 15,793 11.74% 11,387 5.93% 59,027 12.02%
----------- ---------- ----------- --------- ---------- ---------
Three Months Ended March 31, 2000
Utility
--------------------------------------------- Generation
Electric Gas and Trading
---------------------- --------------------- ---------------------
Operating revenues:
External customers................... $125,922 99.86% $94,545 100.00% $100,475 56.99%
Intersegment revenues................ 177 0.14 - 0.00 75,822 43.01
---------- ----------- ---------- --------- ----------- ---------
Total revenues....................... 126,099 100.00 94,545 100.00 176,297 100.00
---------- ----------- ---------- --------- ----------- ---------
Cost of energy sold.................... 1,133 0.90 57,833 61.17 108,757 61.69
Intersegment purchases................. 75,822 60.13 - 0.00 177 0.10
---------- ----------- ---------- --------- ----------- ---------
Total fuel costs..................... 76,955 61.03 57,833 61.17 108,934 61.79
---------- ----------- ---------- --------- ----------- ---------
Gross margin........................... 49,144 38.97 36,712 38.83 67,363 38.21
---------- ----------- ---------- --------- ----------- ---------
Administrative and other costs......... 9,077 7.20 9,913 10.48 4,295 2.44
Energy production costs................ 416 0.33 368 0.39 34,858 19.77
Depreciation and amortization.......... 8,326 6.60 5,366 5.68 10,312 5.85
Transmission and distribution costs.... 7,863 6.24 7,401 7.83 8 0.00
Taxes other than income taxes.......... 3,330 2.64 1,975 2.09 2,767 1.57
Income taxes........................... 6,099 4.84 3,571 3.78 1,428 0.81
---------- ----------- ---------- --------- ----------- ---------
Total non-fuel operating expenses.... 35,111 27.84 28,594 30.24 53,668 30.44
---------- ----------- ---------- --------- ----------- ---------
Operating income....................... $14,033 11.13% $ 8,118 8.59% $ 13,695 7.77%
---------- ----------- ---------- --------- ----------- ---------
29
Three Months Ended March 31, 2001 Compared to
Three Months Ended March 31, 2000
UTILITY OPERATIONS
Electric - Operating revenues increased $8.4 million (6.7%) for the
period to $134.5 million. Contributing to the increase was an increase in retail
electricity delivery of 1.72 million MWh in 2001 compared to 1.66 million MWh
delivered in the prior year period, a 3.8% improvement which increased revenues
$4.8 million period-over-period. This increased volume was the result of a
weather-driven increase in consumption and load growth. In addition,
transmission wheeling revenues increased $2.1 million as a result of additional
capacity sales and other revenues increased $1.4 million primarily for new
property leasing for telecommunication systems.
The gross margin, or operating revenues minus cost of energy sold,
increased $2.9 million but declined slightly as a percentage of revenues. This
dollar increase reflects the increased energy sales and the telecommunication
property leasing, partially offset by an increase in intersegment transfer
pricing. Gross margin as a percentage of revenues declined from 39.0% to 38.7%.
The decline in gross margin percentage is primarily a result of the increase in
intersegment transfer pricing. The Company's Generation and Trading Operations
exclusively provide power to Electric. Intersegment purchases for the Generation
and Trading Operations are priced using internally developed transfer pricing
and are not based on market rates. Customer rates for electric service are set
by the PRC based on the recovery of the cost of power production and a rate of
return that includes certain generation assets that are part of Generation and
Trading Operations, among other things.
Administrative and general costs increased $0.7 million (7.2%) for the
period. This increase is largely due to increased pension and benefits expense
resulting primarily from lower than expected investment returns on related plan
assets. As a percentage of revenues, administrative and other costs remained
constant at 7.2% for the three months ended March 31, 2001 and 2000,
respectively, as a result of cost control measures.
Taxes other than income decreased $0.8 million (24.1%) due to higher
tax liabilities in the prior year period as a result of audits by certain tax
authorities. Taxes other than income as a percentage of revenues decreased to
1.9% from 2.6%.
Gas - Operating revenues increased $97.4 million (103.0%) for the
period to $191.9 million. This increase was driven by an 80.2% increase in the
average rate charge per decatherm due to high wholesale gas prices in the first
quarter of 2001 as a result of increased market demand for natural gas, a 14.6%
volume increase and a gas rate increase which became effective October 30, 2000.
Residential and commercial customers volume increased 14.3% due to a colder
winter during 2001. Customer volume, other than residential and commercial,
increased 14.8%. This growth was primarily attributed to industrial customers
such as the Company's Generation and Trading Operations whose increased demand
was driven by the strong power market prevailing in the Western United States
during the first quarter of 2001. In the second quarter of 2001, the Company's
Generation and Trading operations began procuring its gas supply independent of
the Company and contracting with the Company only for transportation services.
30
The gross margin, or operating revenues minus cost of energy sold,
increased $6.8 million (18.4%). This increase is due to the rate increase and
higher distribution volumes on which the Company earns cost of service revenues.
The Company purchases natural gas in the open market and resells it at cost to
its distribution customers. As a result, the increase in gas prices driving
increased cost of sales revenues does not have an impact on the Company's gross
margin or earnings.
Administrative and general costs increased $2.3 million (23.1%). This
increase is due largely to increased pension and benefits expense as well as
increased bad debt costs of $1.3 million recognized in anticipation of a higher
than normal delinquency rate driven by the significantly higher natural gas
prices experienced in the 2000-2001 heating season. This trend is similar to
historic collection trends associated with past natural gas price spikes.
GENERATION AND TRADING OPERATIONS
Operating revenues grew $314.9 million (178.6%) for the period to
$491.2 million. This increase in wholesale electricity sales reflects strong
regional wholesale electric prices caused by limited power generation capacity,
increased natural gas prices and the power supply/demand imbalance in the
Western United States. These factors contributed to unusually high wholesale
prices which the Company does not believe to be sustainable in the long-term,
but may continue to affect markets in 2001 and 2002. In addition, these factors
have led to an extremely volatile wholesale electric power market with
significant risk (see Other Issues Facing the Company - Western United States
Wholesale Power Market). The Company delivered wholesale (bulk) power of 3.2
million MWh of electricity this period compared to 3.4 million MWh delivered in
the prior period, a decrease of 6.1%. The MWh decrease is attributable to
decreased trading activity during the period. Lower trading volumes are related
to the volatile market and the Company's risk management policies, which limit
certain transactions in this environment. The majority of the wholesale sales,
in the current quarter, are from power purchased for resale. Exposure to adverse
market moves is limited through an asset backed strategy, whereby the Company's
aggregate net open position is covered by its generation resources, primarily
generation which has been excluded from retail rates. This strategy, along with
the Company's credit policies, limit the Company's wholesale sales in a volatile
market. Wholesale revenues from third-party customers increased from $100.5
million to $410.2 million, a 308.3% increase. The increase was largely price
driven.
The gross margin, or operating revenues minus cost of energy sold,
increased $76.6 million (113.7%). Higher margins were partially offset by $13.2
million of allowances against revenues associated with the Company's assessment
of credit and market risk in the wholesale market (see Other Issues Facing The
Company - Western United States Wholesale Power Market) and unrealized
mark-to-market losses of $3.6 million which the Company recognized relating to
its power trading contracts (see Note 4 of the Notes to Consolidated Financial
Statements). These items were recorded as revenue adjustments. Gross margin as a
percentage of revenues decreased from 38.2% to 29.3% reflecting higher cost of
energy purchased.
Administrative and general costs increased $0.7 million (15.5%) for the
period. This increase is primarily due to increased pension and benefits
expense. As a percentage of revenues, administrative and other costs decreased
to 1.0% from 2.4% for the three months ended March 31, 2001 and 2000,
respectively as a result of increased revenues and cost control measures.
31
Energy production costs decreased $0.6 million (1.6%) for the year. The
decrease is due to higher maintenance costs in 2000 resulting from scheduled and
unscheduled outages at San Juan Unit 3 and Four Corners Unit 4. As a percentage
of revenues, energy production costs decreased from 19.8% to 7.0%. The decrease
is primarily due to the significant increase in energy revenues and cost cutting
measures.
Depreciation and amortization increased $0.6 million (5.7%) for the
period due to a higher depreciable plant base. Depreciation and amortization as
a percentage of revenues decreased from 5.7% to 2.2% due to the increase in
energy revenues.
Taxes other than income decreased $0.8 million (30.6%) due to higher
tax liabilities in the prior year period as a result of audits by certain tax
authorities. Taxes other than income as a percentage of revenues decreased from
1.6% to 0.4% as a result of the increase in energy revenues.
UNREGULATED BUSINESSES
Avistar continued to experience lower business volumes resulting from
slow developing markets associated with its new product offerings. Operating
losses for Avistar decreased from $1.2 million in the prior year period to $0.9
million in the current year period due to higher interest income on cash
balances.
CONSOLIDATED
Corporate administrative and general costs, which represent costs
that are driven exclusively by corporate-level activities, increased $4.0
million for the period. This increase was due to higher legal costs associated
with increased business activity and expansion planning and bonus accruals due
to increased earnings, partially offset by reorganizational costs that were
incurred in 2000 in anticipation of separating utility operations under the
Restructuring Act, which has since been delayed (see "Restructuring The Electric
Utility Industry").
Other income and deductions, net of taxes, decreased $4.9 million for
the period to $2.6 million primarily due to valuation losses of $8.3 million
(pre-tax) related to investments in two energy-related technology companies. The
current year also had decreased mark-to-market fair values on the corporate
hedge and the PVNGS decommissioning trust assets (see Note 4 to the Consolidated
Financial Statements) and costs related to the Company's proposed acquisition of
Western Resources' electric utility operations. The Company expects to continue
to incur acquisition related costs in 2001 and beyond.
The Company's consolidated income tax expense was $42.6 million in
the three months ended March 31, 2001, an increase of $29.9 million for the
period. The Company's income tax effective rate for the three months ended March
31, 2001 was 40.15%. Included in the Company's 2001 taxable income are certain
non-deductible costs related to the Company's acquisition of Western Resources'
electric utility operations. Excluding these costs, the Company's effective tax
rate was 39.0%. The Company's effective tax rate for the three months ended
March 31, 2000 was 36.7%. The increase in the rate was primarily due to an
increase in the depreciation of flow-through items.
32
The Company's net earnings for the three months ended March 31, 2001
were $63.6 million, a 189.5% increase. Excluding the Western Resources'
acquisition costs and the related impact on the effective tax rate ("2001
Special Items"), the Company's net earnings were $65.4 million. Net earnings for
the three months ended March 31, 2000 were $22.0 million. Net earnings from
continuing operations excluding the 2001 Special Items increased from $22.0
million in 2000 to $65.4 million in 2001.
Earnings per share on a diluted basis were $1.65 (excluding the 2001
Special Items) for the three months ended March 31, 2001 compared to $0.55 for
the three months ended March 31, 2000. Diluted weighted average shares
outstanding were 39.6 million and 40.0 million in 2001 and 2000, respectively.
The decrease reflects the common stock repurchase program in 2000. Net earnings
per share from continuing operations primarily increased due to expansion of the
Company's wholesale energy trading activities and the common stock repurchase
program.
FUTURE EXPECTATIONS
On April 18, 2001, the Company announced that it was revising its 2001
earnings expectations. The Company now expects full year 2001 earnings to be
significantly higher than previously forecasted. The continuing volatility in
the wholesale power market makes further specific earnings guidance for the year
unrealistic. While forecasting a substantial increase in earnings for 2001 and
2002, management does not believe those gains are sustainable over the longer
term. As conservation measures take effect in California and throughout the
west, and as new generation comes on-line over the next two to three years,
management expects that prices will stabilize at somewhat lower levels.
Looking at the forward prices for power and natural gas and the
Company's market positioning and base earnings ability, management believes that
its earnings are sustainable at around $3.50 a share. Currently high wholesale
prices have the potential to raise earnings substantially above that level in
the near term but management believes that earnings at these higher levels are
not sustainable over the long run. As the Company adds new generation resources,
it is expected that earnings will trend upwards, although at a rate less than
the 10 percent annual growth rate previously targeted by management due to the
higher base earnings the Company has forecasted.
The Company's strategic plan to double generation will provide electric
wholesale volume growth beginning in 2002 and in the later years of the
forecast. These expectations are all stand-alone forecasts and do not take into
account the likely impact of the proposed acquisition of Western Resources.
The Company has previously stated that based on assumptions at the time it
expected its acquisition of Western Resources' electric utility assets to be
immediately accretive to earnings. Since that time, the Company's earnings
expectations for its stand-alone operations have increased significantly while
Western Resources reported earnings have declined for the year ended December
31, 2000 as compared to the year ended December 31, 1999. In addition, Western
Resources' earnings outlook may also be influenced by the outcome of its
electric utility rate case (see "Other Issues Facing the Company - Acquisition
of Western Resources Electric Operations"). Calculations regarding
accretion/dilution are subject to many key assumptions with a high degree of
volatility, including assumptions regarding future earnings for both companies,
which in turn are subject to assumptions regarding
33
rate case decisions, terms and conditions of regulatory approvals for the
transactions and market conditions. Based on updated information regarding the
Company's earnings outlook and Western Resources historic results, the Company's
previous forecast of the combined company would now show earnings dilution.
Whether or not the combination would be dilutive or accretive is highly
dependent on future events that cannot be predicted at this time, including the
results of the pending Western Resources rate case and terms and conditions that
might be imposed as a result of the applications for regulatory approvals.
Management's revised expectations are based on its current view of the
wholesale power market. Management's previous expectations with regard to the
Company's utility operations and non-fuel operating and maintenance expenses
remain largely unchanged. Management's expectations for 2001 assume retail sales
growth will continue at rates comparable to what was experienced in 2000 and the
full realization of the favorable outcome of the two gas rate cases settled in
August of 2000. Expenses are expected to increase due to inflation, the overall
impact of the decline in the investment marketplace of pension and employee
benefit plans, growth initiatives and regulatory filing costs. These earnings
estimates do not include any costs related to the Company's acquisition of the
electric utility assets of Western Resources which are expected to be
approximately $10 to $15 million. The significant capital additions in 2000 are
expected to result in increased depreciation and amortization expense in 2001.
In addition, because of initiatives undertaken in 2000, it is expected that
reduced losses in the non-regulated businesses will contribute to net earnings.
This discussion of future expectations is forward looking information
within the meaning of Section 21E of the Securities Exchange Act of 1934. The
achievement of expected results is dependent upon the assumptions described in
the preceding discussion, and is qualified in its entirety by the Private
Securities Litigation Reform Act of 1995 disclosure - (see "Disclosure Regarding
Forward Looking Statements" below) - and the factors described within the
disclosure which could cause the Company's actual financial results to differ
materially from the expected results enumerated above.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2001, the Company had working capital of $231.9 million
including cash and cash equivalents of $161.3 million. This is an increase in
working capital of $84.1 million from December 31, 2000. This increase primarily
reflects increased cash receipts related to the Company's activity in the
wholesale power market.
Cash generated from operating activities in the three months ended
March 31, 2001 was $109.5 million, an increase of $73.9 million from 2000. This
increase was primarily the result of increased profitability and timing of
accounts payable payments. In addition, the Company did not make first quarter
estimated income tax payments because of an automatic extension granted by the
IRS to taxpayers in several counties in New Mexico as a result of wildfires in
2000. This cash increase was partially offset by an increase in the Company's
receivables due to higher gas prices and increased wholesale electricity sales.
Cash used for investing activities was $47.2 million in 2001 compared
to $16.9 million in 2000. This increased spending reflects $14.0 million related
to the acquisition of transmission assets and combustion turbine progress
payments of $14.5 million.
34
Cash used for financing activities was $8.7 million was primarily used
to fund dividend requirements. This compared to $60.1 million used in 2000. This
decrease reflects the 2000 repurchase of $34.7 million of senior unsecured notes
at a cost of $32.8 million and common stock repurchases in 2000 (see "Stock
Repurchase" below).
Capital Requirements
Total capital requirements include construction expenditures as well as
other major capital requirements and cash dividend requirements for both common
and preferred stock. The main focus of the Company's construction program is
upgrading generation systems, upgrading and expanding the electric and gas
transmission and distribution systems and purchasing nuclear fuel. In addition,
the Company anticipates significant expenditures to expand its generation
capabilities. Projections for total capital requirements and construction
expenditures for 2001 are $370 million and $353 million, respectively. Such
projections for the years 2001 through 2005 are $1.52 billion and $1.45 billion,
respectively. These estimates are under continuing review and subject to
on-going adjustment (see "Competitive Strategy" above).
The Company's construction expenditures for 2001 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 2001 through 2005. To cover the difference in
the amounts and timing of cash generation and cash requirements, the Company
intends to use short-term borrowings under its liquidity arrangements.
Liquidity
At May 1, 2001, 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 May 1, 2001.
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 the Company's securities ratings on negative credit
watch pending review of the transaction. The Company is committed to maintaining
its investment grade. S&P currently rates the Company's senior unsecured notes
("SUNs") and its Eastern Interconnection Project ("EIP") senior secured debt
"BBB-" and its preferred stock "BB". Moody's rates the Company's SUNs and senior
unsecured pollution control revenue bonds "Baa3"; and preferred stock "ba1". The
EIP senior secured debt are also rated "Ba1". Fitch rates the Company's SUNs and
senior unsecured pollution control revenue bonds "BBB-," the Company's EIP lease
obligation "BB+" and the Company's preferred stock "BB-." Investors are
35
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.
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
The Company currently has no maturities of long-term financings during
the period of 2001 through 2004, not considering the impact of the acquisition
of the Western Resources' electric utility operations. However, during this
period, the Company could enter into long-term financings for the purpose of
strengthening its balance sheet, funding growth and reducing its cost of
capital. The Company continues to evaluate its investment and debt retirement
options to optimize its financing strategy and earnings potential. No additional
first mortgage bonds may be issued under 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
Previously, the Company provided details of its proposed holding
company plan as contemplated in response to the implementation dates established
under the Restructuring Act before it was amended in February of 2001 (see
"Restructuring of the Electric Utility Industry" above). As a result of the
amendments to the Restructuring Act delaying customer choice and corporate
restructuring for five years, the Company has modified its previously reported
holding company plan.
Currently, the Company plans to implement a holding company structure
as permitted under the amended Restructuring Act. This structure provides for a
holding company whose current holdings will be the Company, Avistar and other
inactive unregulated subsidiaries. This is expected to be effected through a
share exchange between current company shareholders and the proposed holding
company, PNM Resources, which is currently a wholly-owned subsidiary of the
Company. Avistar and the other inactive unregulated subsidiaries are expected to
become wholly-owned subsidiaries of the holding company. There are no current
plans to provide the proposed holding company with significant debt financing.
The Company's revised holding company plan is subject to regulatory and other
approvals. Accordingly, the revised plan may be subject to significant changes
before implementation.
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. From August 8, 2000 through December 31, 2000 Company
repurchased an additional 417,900 shares of its outstanding common stock at a
36
cost of $9.0 million. The Company made no repurchases of its stock during the
three months ended March 31, 2001. The Company has no current authorization from
its Board of Directors to acquire stock.
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 (as amended), future growth plans and the
related capital requirements and standard business considerations will also
affect the Company's ability to pay dividends.
Capital Structure
The Company's capitalization, including current maturities of long-term
debt, at March 31, 2001 and December 31, 2000 is shown below:
March 31, December 31,
2001 2000
--------- ----------
Common Equity..................... 51.2 % 47.4 %
Preferred Stock................... 0.7 0.7
Long-term Debt.................... 48.1 51.9
--------- ----------
Total Capitalization*.......... 100.0 % 100.0 %
========= ==========
* Total capitalization does not include as debt the present value of
the Company's lease obligations for PVNGS Units 1 and 2 and EIP,
which was $166 million as of March 31, 2001 and $162 million as of
December 31, 2000.
OTHER ISSUES FACING THE COMPANY
RECOVERY OF CERTAIN COSTS UNDER THE RESTRUCTURING ACT
Stranded Costs
The Restructuring Act, as amended, recognizes that electric utilities
should be permitted a reasonable opportunity to recover an appropriate amount of
the costs previously incurred in providing electric service to their customers
("stranded costs"). Stranded costs represent all costs associated with
generation-related assets, currently in rates, in excess of the expected
competitive market price over the life of those assets and include plant
decommissioning costs, regulatory assets, and lease and lease-related costs.
Utilities will be allowed to recover no less than 50% of stranded costs through
a non-bypassable charge on all customer bills for five years after
implementation of customer choice. The PRC could authorize a utility to recover
up to 100% of its stranded costs if the PRC finds that recovery of more than
50%: (i) is in the public interest; (ii) is necessary to maintain the financial
integrity of the public utility; (iii) is necessary to continue adequate and
reliable service; and (iv) will not cause an increase in rates to residential or
small business customers during the transition period. The Restructuring Act, as
37
amended, also allows for the recovery of nuclear decommissioning costs by means
of a separate wires charge over the life of the underlying generation assets
(see "NRC Prefunding" below).
The calculation of stranded costs is subject to a number of highly
sensitive assumptions, including the date of open access, appropriate discount
rates and projected market prices, among others. The Restructuring Act, as
amended, requires the Company to file a transition plan which includes
provisions for the recovery of stranded costs and other expenses associated with
the transition to a competitive market no later than January 1, 2005. The
Company is unable to predict the amount of stranded costs that it may file to
recover at that time. The Company's previous proposal to recover its stranded
costs under the original customer choice implementation dates would not
accurately represent the Company's expected stranded costs under the amended
implementation dates of the Restructuring Act.
Approximately $143 million of costs associated with the power supply
and energy services businesses under the Restructuring Act were established as
regulatory assets. Because of the Company's belief that recovery is probable,
these 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." The amendments to the Restructuring Act allow the Company to recover a
portion of its stranded cost assets, related to coal mine decommissioning of
$114 million, over the five-year recovery period beginning January 1, 2002.
Under the provisions of the law, the Company cannot increase electric utility
rates to recover these mine reclamation costs. Accordingly, this provision
effectively limits the Company's recovery of certain generation related costs in
its current rates. With regard to future rate cases that may occur before
restructuring is implemented, these impacted generation costs are recoverable to
the extent a future rate case results in rates that include recovery of these
costs. The Company believes that the remaining stranded cost assets will be
fully recovered in current or future rates.
The Company believes that the Restructuring Act, as amended, 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. The PRC will
make a determination and quantification of stranded cost recovery prior to
implementation of restructuring. The determination may have an impact on the
recoverability of the related assets and may have a material effect on the
future financial results and position of the Company.
Transition Cost Recovery
In addition, the Restructuring Act, as amended, authorizes utilities to
recover in full any prudent and reasonable costs incurred in implementing full
open access ("transition costs"). These transition costs are currently scheduled
to be recovered through 2012 by means of a separate wires charge. The PRC may
extend this date by up to one year. The Company is unable to predict the amount
of transition costs it may incur. To date, the Company has capitalized $19.1
million of expenditures that meet the Restructuring Act's definition of
transition-related costs. Transition costs for which the Company will seek
recovery include professional fees, financing costs, consents relating to the
transfer of assets, management information system changes including billing
38
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.
NRC Prefunding
Pursuant to NRC rules on financial assurance requirements for the
decommissioning of nuclear power plants, the Company has a program for funding
its share of decommissioning costs for PVNGS through a sinking fund mechanism
(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, as amended, allows for the recoverability of 50%
up to 100% of stranded costs including nuclear decommissioning costs (see
"Stranded Costs"). The Restructuring Act, as amended, specifically identifies
nuclear decommissioning costs as eligible for separate recovery over a longer
period of time than other stranded costs if the PRC determines a separate
recovery mechanism to be in the public interest. In addition, the Restructuring
Act, as amended, states that it 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.
When final determination of stranded cost recovery is made and if the Company is
unable to meet the requirements of the NRC rules permitting the use of an
external sinking fund because it is unable to recover all of its estimated
decommissioning costs through a non-bypassable charge, the Company may have to
pre-fund or find a similarly capital intensive means to meet the NRC rules.
There can be no assurance that such an event will not negatively affect the
funding of the Company's growth plans.
ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS
On November 9, 2000, the Company and 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 an agreement and plan of restructuring and merger,
the Company and Western Resources, whose utility operations consist of its
Kansas Power and Light ("KPL") division and Kansas Gas and Electric ("KGE")
subsidiary, will both become subsidiaries of a new holding company to be named
at a future date. Prior to and as a condition to, the consummation of this
combination, Western Resources will reorganize all of its non KPL and KGE
assets, including its 85% stake in Protection One and its 45% investment in
ONEOK, into Westar Industries which will be spun off to Western Resources'
shareholders prior to the acquisition of Western's electric utility assets by
the Company.
39
The new holding company will issue 55 million of its shares, subject to
adjustment, to Western Resources' shareholders and Westar Industries and 39
million shares to the Company's shareholders. Before any adjustments, the new
company will have approximately 94 million shares outstanding, of which
approximately 41% will be owned by former Company shareholders and 59% will be
owned by former Western Resources shareholders and Westar Industries.
In the transaction, each Company share will be exchanged on a
one-for-one basis for shares in the new holding company. The portion of each
Western Resources share not converted into Westar stock in connection with the
spin-off will be exchanged for a fraction of a share of the new holding company
in accordance with an exchange ratio to be finalized at closing, depending on
the impact of certain adjustments to the transaction consideration. Under the
terms of the agreement, Western Resources and Westar Industries have been given
an incentive to reduce Western Resources net debt balance prior to the
consummation of the transaction. The agreement contains a mechanism to adjust
the transaction consideration based on certain activities not affecting the
utility operations, which increase the equity of the utility. In addition,
Westar Industries has the option of making 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. 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 February 28, 2001, Westar purchased 14.4 million Western Resources
common shares at $24.358 per share (based on a 20 day look-back price at
February 28, 2001) at an aggregate price of $350 million. As a result of this
equity contribution, the acquisition consideration may be adjusted to include an
additional 4.3 million shares of the new holding company depending on the impact
of future transactions between Western Resources and Westar.
The transaction will be accounted for as a reverse acquisition by the
Company as the former 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.
Based on the volume weighted average closing price of the Company's
common stock over the two days prior and two days subsequent to the announcement
of the transaction of $24.149 per share, the indicated equity consideration of
the transaction was approximately $945 million, excluding the potential issuance
of additional shares discussed above. There is approximately $2.9 billion of
existing Western Resources debt giving the transaction an aggregate enterprise
value of approximately $3.8 billion. There are plans for the new holding company
to reduce and refinance a portion of the Western Resources debt.
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
40
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.
The Company expects that the shareholders of the new holding company
will receive the Company's dividend. The Company's current annual dividend is
$0.80 per share. There can be no assurance however that any funds, property or
shares will be legally available to pay dividends at any given time or if
available, the new holding company's Board of Directors will declare a dividend.
On November 27, 2000, Western Resources filed a combined electric rate
case requesting a combined $151 million rate increase with the Kansas
Corporation Commission (KCC). On April 6, 2001, the KCC filed testimony in the
Western rate case recommending a combined rate decrease of $91.7 million.
Western Resources has filed rebuttal testimony and hearings are scheduled to be
held on the matter. The KCC is required by law to reach a decision by July 28,
2001.
The Company has previously stated that based on assumptions at the time it
expected its acquisition of Western Resources' electric utility assets to be
immediately accretive to earnings. Since that time, the Company's earnings
expectations for its stand-alone operations have increased (see "Future
Expectations") significantly while Western Resources reported earnings have
declined for the year ended December 31, 2000 as compared to the year ended
December 31, 1999. In addition, Western Resources' earnings outlook may also be
influenced by the outcome of its electric utility rate case now before the KCC
(see above). Calculations regarding accretion/dilution are subject to many key
assumptions with a high degree of volatility, including assumptions regarding
future earnings for both companies, which in turn are subject to assumptions
regarding rate case decisions, terms and conditions of regulatory approvals for
the transactions and market conditions. Based on updated information regarding
the Company's earnings outlook and Western Resources historic results, the
Company's previous forecast of the combined company would now show earnings
dilution. Whether or not the combination would be dilutive or accretive is
highly dependent on future events that cannot be predicted at this time,
including the results of the pending Western Resources rate case and terms and
conditions that might be imposed as a result of the applications for regulatory
approvals.
On May 8, 2001, the KCC commenced an investigation of the proposed
split-off of Westar Industries from Western Resources and whether the
transaction will adversely affect the ability of Western Resources' electric
utility operations to provide efficient and sufficient electric utility service
at just and reasonable rates to its customers in the state of Kansas. The
successful split-off of Westar is a condition of the proposed acquisition of
Western Resources' electric utility assets.
The companies expect the transaction to be completed within the next 12 to
15 months. 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
41
Commission, the New Mexico Public Regulation Commission, the Federal Energy
Regulatory Commission, the Nuclear Regulatory Commission, the Federal
Communications Commission and the Department of Justice under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976. In addition, an adverse
regulatory outcome related to other actions involving rate making or approval of
regulatory plans may affect the consummation of the transaction. 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.
WESTERN UNITED STATES WHOLESALE POWER MARKET
A significant portion of the Company's earnings in 2001 was derived
from the Company's wholesale power trading operations which benefited from the
strong demand and high wholesale prices in the Western United States. These
market conditions were primarily driven by the electric power supply shortages
in the Western United States. As a result of the supply imbalance, the wholesale
power market in the Western United States has become extremely volatile and,
while providing many marketing opportunities, presents significant risk to
companies selling power into this marketplace.
The power market in the Western United States has been the subject of
widespread national attention and continues to evolve on nearly a daily basis.
At the heart of the situation are flaws in the California deregulation
legislation and a significant imbalance between electric supply and demand.
These circumstances have been aggravated by other factors such as increases in
gas supply costs, weather conditions and transmission constraints. Congress and
the California legislature are considering various legislation that would
provide long or short-term relief, including potentially price caps on the
wholesale price of electricity that could be charged, relaxation of certain
environmental standards, and windfall profit taxes on sellers into the
California wholesale market. The FERC and the California Public Utilities
Commission ("CPUC") have also entered a series of orders addressing,
respectively, the wholesale pricing of electricity into the California market
and the retail pricing of electricity to California consumers. These
initiatives, individually or collectively, could place significant downward
pressure on wholesale prices. The Company cannot predict the ultimate outcome of
these governmental initiatives and their effect on the Western United States
power market or on the Company's ability to market into the California market.
During 2001, regional wholesale electricity prices have reached over
$1,000 per MWh mainly due to the electric power shortages in the West. Two of
California's major utilities, SCE and PG&E, have been unable to fully recover
their wholesale power costs from their ratepayers. As a result, both utilities
experienced severe liquidity constraints that caused PG&E to seek bankruptcy
protection while SCE has been forced to consider bankruptcy. In response to the
turmoil in the California energy market, the FERC initially imposed a "soft"
price cap of $150 per MWh for sales to the California Power Exchange ("Cal PX")
and the California Independent System Operator ("Cal ISO") that required any
wholesale sales of electricity into the these markets be capped at $150 MWh
unless the seller could demonstrate that its costs exceed the cap. This price
cap was effectively modified by three FERC orders issued in March and April 2001
that directed certain power suppliers to provide refunds in excess of $100
million for overcharges calculated on the basis of a formula that sanctioned
wholesale prices considerably in excess of the $150/MWh level. On April 26,
2001, the FERC adopted an order establishing prospective mitigation and a
monitoring plan for the California wholesale markets and which established a
further investigation of public utility rates in wholesale Western energy
42
markets. The plan reflected in the April 26 order replaced the $150/MWh soft cap
previously established and would apply during periods of system emergency. The
Company is presently evaluating the effects, if any, of the April 26 order on
its wholesale marketing efforts into the California markets. In addition, in
April 2001, SCE and the Governor of California announced an agreement in which
the state would purchase SCE's 12,000 mile transmission system for $2.8 billion.
In exchange, SCE agreed to sell power from its plants under cost-based, rather
than market-based pricing for the next 10 years. The agreement still requires
federal regulatory and California legislative approvals. It is unclear what
effect these measures will have on the price of electricity in California and
the surrounding states. Such measures may have an impact on the sustainability
of the high electric power prices experienced in the first quarter of 2001.
In 2001, approximately $2 million in wholesale power sales by the
Company were made directly to the Cal PX, which was the main market for the
purchase and sale of electricity in the state in the beginning of 2001 or the
Cal ISO which manages the state's electricity transmission network. In January
and February 2001, SCE and PG&E, major purchasers of power from the California
PX and ISO, defaulted on payments due the Cal PX for power purchased from the PX
in 2000. These defaults caused the Cal PX to seek bankruptcy protection. The
Company will be filing proofs of claims in the bankruptcy proceeding. At March
31, 2001, amounts due from the Cal PX or Cal ISO for power sold to them totaled
$8.1 million.
Prior to its bankruptcy filing, the Cal PX undertook to charge back
these defaults of SCE and PG&E to other market participants, in proportion to
their participation in the markets. The Company was invoiced for $2.3 million as
its proportionate share under the Cal PX tariff. The Company, as well as a
number of power marketers and generators, filed complaints with the FERC to halt
the Cal PX's attempt to collect these payments under the charge-back mechanism,
claiming the mechanism was not intended for these purposes, and even if it was
so intended, such an application was unreasonable and destabilizing to the
California power market. The FERC has issued a ruling on these complaints
eliminating the "charge-back" mechanism.
With the demise of the Cal PX in February 2001, the California
Department of Water Resources ("Cal DWR") commenced a program of purchasing
electric power needed to supply California utility customers serviced by PG&E
and SCE as these utilities lacked the liquidity to purchase supplies. The
purchases are currently financed by legislative appropriation, but this funding
is expected to be replaced with the issuance of revenue bonds by the state under
recent legislation signed by the California governor. These bonds are expected
to be repaid by the utility ratepayers. In the first quarter of 2001, the
Company began to sell power to the Cal DWR. The Company regularly monitors its
credit risk with regard to its Cal DWR sales and believes its exposure is
prudent.
In addition to sales directly to California, the Company sells power to
customers in other jurisdictions who sell to California and whose ability to pay
the Company may be dependent on payment from California. The Company is unable
to determine whether its non-California power sales ultimately are resold in the
California market. The Company's credit risk is monitored by its Risk Management
Committee, which is comprised of senior finance and operations managers. The
Company seeks to minimize its exposure through established credit limits, a
diversified customer base and the structuring of transactions to take advantage
of off-setting positions with its customers. To the extent these customers who
sell power into California are dependent on payment from California to make
their payments to the Company, the Company may be exposed to credit risk which
did not exist prior to the California situation.
43
In the first quarter of 2001, in response to the increased credit risk
and market price volatility described above, the Company provided an additional
allowance against revenue of $13.2 million for anticipated losses to reflect
management's estimate of the increased risk in the wholesale power market and
its impact on 2001 revenues. This determination was based on a methodology that
considers the credit ratings of its customers and the price volatility in the
marketplace, among other things. Based on information available at March 31,
2001, the Company believes the total allowance for anticipated losses, currently
established at $21.7 million, is adequate for management's estimate of potential
uncollectible accounts. The Company will continue to monitor the wholesale power
marketplace and adjust its estimates accordingly.
The CPUC has commenced an investigation into the functioning of the
California wholesale power market and its associated impact on retail rates. The
Company, along with other power suppliers in California, has been served with a
subpoena in connection with this investigation and has responded to the
subpoena. The Company has been advised that the California Attorney General is
conducting an investigation into possibly unlawful, unfair or anti-competitive
behavior affecting electricity rates in California, and that Company documents
will be subpoenaed in the future in connection with this investigation. Other
related investigations have been commenced by other federal and state
governmental bodies.
In addition, there are several class action lawsuits that have been
filed in California against generators and wholesale sellers of energy into the
California market. These actions allege, in essence, that the defendants engaged
in unlawful and unfair business practices to manipulate the wholesale energy
market, fix prices and restrain supply, and thereby drive up prices. The Company
is not a named defendant in any of these actions.
The Company does not believe that these matters will have a material
adverse effect on its results of operations or financial position.
As noted above, SCE has publicly stated that it may be forced to
declare bankruptcy. SCE is a 15.8% participant in PVNGS and a 48.0% participant
in Four Corners. Pursuant to an agreement among the participants in PVNGS and an
agreement among the participants in Four Corners Units 4 and 5, each participant
is required to fund its proportionate share of operation and maintenance,
capital, and fuel costs of PVNGS and Four Corners Units 4 and 5. The Company
estimates SCE's total monthly share of these costs to be approximately $7.1
million for PVNGS and $8.0 million for Four Corners. The agreements provide that
if a participant fails to meet its payment obligations, each non-defaulting
participant shall pay its proportionate share of the payments owed by the
defaulting participant for a period of six months. During this time the
defaulting participant is entitled to its share of the power generated by the
respective station. After this grace period, the defaulting participant must
make its payments in arrears before it is entitled to its continuing share of
power. As of May 1, 2001, SCE has not defaulted on its payment obligations with
respect to PVNGS and Four Corners. The Company is unable to predict whether the
California situation will cause SCE to default on its payment obligations.
44
Implementation of 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 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 estimated bad debt costs throughout 1999 and 2000.
The Company continued its analysis and collection efforts of its
delinquent accounts resulting from the problems associated with the
implementation of the new customer billing system throughout 2000 and identified
additional bad debt exposure. By the end of 2000, the Company completed its
analysis of its delinquent accounts and resumed its normal collection
procedures. As a result, the Company determined that $13.5 million of customer
receivables would not be collectible. Based upon information available at March
31, 2001, the Company believes the allowance for doubtful accounts of $11.0
million is adequate for management's estimate of potential uncollectible
accounts.
In addition, due to the significantly higher natural gas prices
experienced in November and December 2000, the Company increased its bad debt
expense by approximately $1 million for the three months ended March 31, 2001
and $2 million for the year ended December 31, 2000 in anticipation of higher
than normal delinquency rates. The Company expects this trend to continue as
long as natural gas prices remain higher than historical levels.
The following is a summary of the allowance for doubtful accounts
during the three months ended March 31, 2001 and the year ended December 31,
2000:
March 31, December 31,
2001 2000
------------- ------------
Allowance for doubtful accounts, beginning
of year.................................................... $ 8,963 $12,504
Bad debt expense............................................. 3,434 9,980
Less: Write off (adjustments) of uncollectible accounts..... 1,399 13,521
------------ ------------
Allowance for doubtful accounts, end of year ................ $10,998 $ 8,963
============ ============
Effects of Certain Events on Future Revenues
The Company's 100 MW power sale contract with San Diego Gas and
Electric Company ("SDG&E") expired on April 30, 2001 following FERC's acceptance
for filing of a cancellation notice filed by the Company. The Company expects to
replace these revenues, based on current market conditions. 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 ("WAPA") filed a
petition at the FERC requesting the FERC, on an expedited basis, to order the
Company to provide network transmission service to WAPA under the Company's Open
Access Transmission Tariff on behalf of the United States Department of Energy
45
("DOE") as contracting agent for Kirtland Air Force Base ("KAFB"). On April 13,
2001, the FERC entered an order favorable to the Company, denying the WAPA
transmission application. The order is not yet final. In a related PRC
proceeding, the parties are pursuing informal settlement discussions and
awaiting a PRC order on the scope of the case (See Item 3. - "Legal Proceedings
- - Other Proceedings - KAFB Contract").
COAL FUEL SUPPLY
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 2001 was 68.25% coal, 28.40% nuclear
and 3.35% 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.
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 those
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. The 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-two year term, beginning in 2006,
for replacement of the current USBR contract for 16,200 acre feet 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.
46
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 and is in the process of attempting to
negotiate settlement agreements with one of those other companies. 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 has responded to the
NMED information request.
The nature and cost of the impacts of EPA's changed interpretation of
the application of the NSR and NSPS, together with proposed changes to these
regulations, may be significant to the power production industry. However, the
Company cannot quantify these impacts with regard to its power plants. It is
also unknown what changes in EPA policy, if any, may occur in the NSR area as a
result of the change in administration in Washington. If the EPA should prevail
with its current interpretation of the NSR and NSPS rules, the Company may be
required to make significant capital expenditures which could have a material
adverse effect on the Company's financial position and results of operations.
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 the Federal Comprehensive Environmental Response
Compensation and Liability Act of 1980 and other similar statutes.
The Company records its environmental liabilities when site assessments
or remedial actions are probable and a range of reasonably likely cleanup costs
can be estimated. The Company reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified
site using currently available information, including existing technology,
presently enacted laws and regulations, experience gained at similar sites, and
the probable level of involvement and financial condition of other potentially
47
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 $6.8 million. The ultimate cost to clean up the Company's
identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: the extent and nature
of contamination; the scarcity of reliable data for identified sites; and the
time periods over which site remediation is expected to occur. The Company
believes that, due to these uncertainties, it is remotely possible that cleanup
costs could exceed its recorded liability by up to $11.6 million. The upper
limit of this range of costs was estimated using assumptions least favorable to
the Company.
In 2001, the Company anticipates spending $1.4 million for remediation
and $0.7 million for control and prevention. The majority of the March 31, 2001
environmental liability is expected to be paid over the next five years, funded
by cash generated from operations. Future environmental obligations are not
expected to have a material impact on the results of operations or financial
condition of the Company.
NATURAL GAS EXPLOSION
On April 25, 2001, a natural gas explosion occurred in Santa Fe, New
Mexico. The apparent cause of the explosion was a leak from a Company line near
the location. The explosion destroyed a small building and injured two persons
who were working in the building. At least one passerby received minor injuries
from the blast. Several claims for property and business interruption damages
have been received by the Company. The cause of the leak is unknown and the
Company is conducting an investigation into the explosion. No lawsuits against
the Company have yet been served on the Company. At this time, the Company is
unable to estimate the potential liability, if any, that the Company may incur.
There can be no assurance that the outcome of this matter will not have a
material impact on the results of operations and financial position of the
Company.
NAVAJO NATION TAX ISSUES
APS, the operating agent for Four Corners, has informed the Company
that in March 1999, APS initiated discussions with the Navajo Nation regarding
various tax issues in conjunction with the expiration of a tax waiver, in July
2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to
the possessory interest tax and the business activity tax associated with the
Four Corners operations on the reservation. The Company believes that the
resolution of these tax issues will require an extended process and could
potentially affect the cost of conducting business activities on the
reservation. The Company is unable to predict the ultimate outcome of
discussions with the Navajo Nation regarding these tax issues.
48
NEW AND PROPOSED ACCOUNTING STANDARDS
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities, ("SFAS 133"): The Company
implemented SFAS 133, as amended, on January 1, 2001. SFAS 133, as amended,
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, as amended, also requires that changes in the
derivatives' fair value be recognized currently in earnings unless specific
hedge accounting or normal purchase and sale 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.
SFAS 133, as amended, provides that the effective portion of the gain
or loss on a derivative instrument designated and qualifying as a cash flow
hedging instrument be reported as a component of other comprehensive income and
be reclassified into earnings in the same period or periods during which the
hedged forecasted transaction affects earnings. The results of hedge
ineffectiveness and the change in fair value of a derivative that an entity has
chosen to exclude from hedge effectiveness are required to be presented in
current earnings.
Because the Company's derivative instruments as defined by SFAS 133, as
amended, are currently marked-to-market or are classified as cash flow hedges,
the adoption of SFAS 133, as amended, did not have an impact on the net earnings
of the Company. However, the adoption of SFAS 133, as amended, did increase
comprehensive income by $6.1 million, net of taxes for the recording of the
Company's cash flow hedges. The physical contracts will subsequently be
recognized as a component of the cost of purchased power when the actual
physical delivery occurs. At January 1, 2001, the derivative instruments
designated as cash flow hedges had a gross asset position of $9.9 million on the
hedged transactions. See Note 4 for financial instruments currently
marked-to-market.
It is a common practice within the electric utility industry to net
offsetting purchase and sales contracts between two or more counterparties to
facilitate transmission. This is commonly referred to as a "book-out." Whether a
book-out occurs is dependant on a number of factors, including agreement by all
parties in the chain of the transaction, efficiency of the transaction flow,
congestion on the electrical transmission system, and system reliability issues.
Book-outs do not occur until a short time before the electricity is due to be
physically delivered, no matter when the original contracts in the chain were
entered into, and have no legal standing should one of the parties in the chain
default. The Derivatives Implementation Group ("DIG") of the FASB has reached a
tentative conclusion that all contracts for the sale or purchase of electricity
that are subject to being booked out, whether that is the intent of the
counterparties or not, do not qualify for the normal sale or normal purchase
exception. The conclusion is tentative until formally cleared by the FASB and
incorporated in an FASB staff implementation guide. If the conclusion of the DIG
is accepted by the FASB, the Company may be required to mark-to-market its
transactions that it has classified as normal purchases and normal sales. The
Company is unable to determine the impact of this conclusion.
49
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.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
Statements made in this filing that relate to future events are made
pursuant to the Private Securities Litigation Reform Act of 1995. Readers are
cautioned that such forward-looking statements with respect to revenues,
earnings, performance, strategies, prospects and other aspects of the business
of the Company are based upon current expectations and are subject to risk and
uncertainties, as are the forward-looking statements with respect to the
benefits of the Company's proposed acquisition of Western Resources and the
businesses of the Company and Western Resources. The Company assumes no
obligation to update this information.
Because actual results may differ materially from expectations, the
Company cautions readers not to place undue reliance on these statements. A
number of factors, including weather, fuel costs, changes in supply and demand
in the market for electric power, the performance of generating units and
transmission system, and state and federal regulatory and legislative decisions
and actions, including rulings issued by the New Mexico Public Regulation
Commission pursuant to the Electric Utility Industry Restructuring Act of 1999,
as amended, and in other cases now pending or which may be brought before the
PRC and any action by the New Mexico Legislature to further amend or repeal that
Act, or other actions relating to restructuring or stranded cost recovery, or
federal or state regulatory, legislative or legal action connected with the
California wholesale power market, could cause the Company's results or outcomes
to differ materially from those indicated by such forward-looking statements in
this filing.
In addition, factors that could cause actual results or outcomes
related to the proposed acquisition of Western Resources to differ materially
from those indicated by such forward looking statements include, but are not
limited to, risks and uncertainties relating to: the possibility that
shareholders of the Company and/or Western Resources will not approve the
transaction, the risks that the businesses will not be integrated successfully,
the risk that the benefits of the transaction may not be fully realized or may
take longer to realize than expected, disruption from the transaction making it
more difficult to maintain relationships with clients, employees, suppliers or
other third parties, conditions in the financial markets relevant to the
proposed transaction, the receipt of regulatory and other approvals of the
transaction, that future circumstances could cause business decisions or
accounting treatment to be decided differently than now intended, changes in
laws or regulations, changing governmental policies and regulatory actions with
respect to allowed revenue requirements, rates of return on equity and equity
ratio limits, industry and rate structure, stranded cost recovery, operation of
nuclear power facilities, acquisition, disposal, depreciation and amortization
50
of assets and facilities, operation and construction of plant facilities,
recovery of fuel and purchased power costs, decommissioning costs, present or
prospective wholesale and retail competition (including retail wheeling and
transmission costs), political and economic risks, changes in and compliance
with environmental and safety laws and policies, weather conditions (including
natural disasters such as tornadoes), population growth rates and demographic
patterns, competition for retail and wholesale customers, availability, pricing
and transportation of fuel and other energy commodities, market demand for
energy from plants or facilities, changes in tax rates or policies or in rates
of inflation or in accounting standards, unanticipated delays or changes in
costs for capital projects, unanticipated changes in operating expenses and
capital expenditures, capital market conditions, competition for new energy
development opportunities and legal and administrative proceedings (whether
civil, such as environmental, or criminal) and settlements, and the impact of
Protection One's financial condition on Western Resources' consolidated results.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company uses derivative financial instruments to manage risk as it
relates to changes in natural gas and electric prices and also adverse market
changes for investments held by the Company's various trusts. The Company also
uses certain derivative instruments for bulk power electricity trading purposes
in order to take advantage of favorable price movements and market timing
activities in the wholesale power markets. Information about market risk is set
forth in Note 4 to the Notes to the Consolidated Financial Statements and
incorporated by reference. The following additional information is provided.
The Company uses value at risk ("VAR") to quantify the potential
exposure to market movement on its open contracts and excess generating assets.
The VAR is calculated utilizing the variance/co-variance methodology over a
three day period within a 99% confidence level. The Company's VAR as of March
31, 2001 from its electric trading contracts was $31.8 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 VAR 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. In addition, the Company is exposed to credit losses in the
event of non-performance or non-payment by counterparties. The Company uses a
credit management process to access and monitor the financial conditions of
counterparties. Credit exposure is also regularly monitored by the Company's
Risk Management committee.
The VAR represents an estimate of the potential gains or losses that
could be recognized on the Company's wholesale power marketing portfolio given
current volatility in the market, and is not necessarily indicative of actual
51
results that may occur, since actual future gains and losses will differ from
those estimated. Actual gains and losses may differ due to actual fluctuations
in market rates, operating exposures, and the timing thereof, as well as changes
to the Company's wholesale power marketing portfolio during the year.
The Company's outstanding long-term debt is fixed rate debt and not
subject to interest rate fluctuation. The Company has not historically utilized
interest rate swaps or similar hedging arrangements to protect against
fluctuations in interest rates.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The following represents a discussion of legal proceedings that first
became a reportable event in the current year or material developments for those
legal proceedings previously reported in the Company's 2000 Annual Report on
Form 10-K ("Form 10-K"). This discussion should be read in conjunction with Item
3. - Legal Proceedings in the Company's Form 10-K.
PVNGS Water Supply Litigation
As previously reported, The Company understands that a summons served
on APS in 1986 required all water claimants in the Lower Gila River Watershed of
Arizona to assert any claims to water on or before January 20, 1987, in an
action pending in the Maricopa County Superior Court. PVNGS is located within
the geographic area subject to the summons and the rights of the PVNGS
participants, including the Company, to the use of groundwater and effluent at
PVNGS are potentially at issue in this action. APS, as the PVNGS project
manager, filed claims that dispute the court's jurisdiction over the PVNGS
participants' groundwater rights and their contractual rights to effluent
relating to PVNGS and, alternatively, seek confirmation of such rights. In
November 1999, the Arizona Supreme Court issued a decision confirming that
certain groundwater rights may be available to the federal government and Indian
tribes. APS and other parties have petitioned the United States Supreme Court
for review of this decision and the petition was denied. In addition, the
Arizona Supreme Court issued a decision affirming the lower court's criteria for
solving groundwater claims. APS and other parties filed motions for
reconsideration on one aspect of that decision. Those motions have been denied
by the Arizona Supreme Court. APS and other parties have petitioned the United
States Supreme Court for review of the Arizona Supreme Court's decision
affirming the lower court's criteria for resolving groundwater claims. The
Company is unable to predict the outcome of this case.
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
52
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 DC Circuit 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
filed a petition for writ of certiorari to the United States Supreme Court,
which was denied on April 16, 2001. The Company does not expect any immediate
impacts as a result of this decision but will continue to monitor developments
with the Navajo Nation and EPA.
The Company cannot predict the outcome of these proceedings or any
subsequent determinations by the EPA. There can be no assurance that the outcome
of these matters will not have a material impact on the results of operations
and financial position of the Company.
KAFB Contract
The Company reported previously that the DOE had entered into an agency
agreement with WAPA on behalf of KAFB, one of the Company's largest retail
electric customers, by which WAPA would competitively procure power for KAFB.
The proposed wholesale power procurement was to begin at the expiration of
KAFB's power service contract with the Company in December 1999. On May 4, 1999,
the Company received a request for network transmission service from WAPA
pursuant to Section 211 of the Federal Power Act to facilitate the delivery of
wholesale power to KAFB over the Company's transmission system. The Company
denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB
is and will continue to be a retail customer until the effective date KAFB can
elect customer choice service under the provisions of the Restructuring Act of
1999. The Company also cited several provisions of Federal law that prohibit the
provision of such service to WAPA. On September 30, 1999, WAPA filed a petition
at the FERC requesting the FERC, on an expedited basis, to order the Company to
provide network transmission service to WAPA under the Company's Open Access
Transmission Tariff on behalf of DOE and several other entities located on KAFB.
The petition claimed KAFB is a wholesale customer of the Company, not a retail
customer. By order entered on April 13, 2001 the FERC denied the WAPA
transmission application. The FERC order determined, among other things, that
WAPA had failed to demonstrate that its sales to DOE are sales for resale and
also that WAPA failed to qualify for certain claimed exemptions under the
Federal Power Act that would have entitled it to provide expanded service to
DOE. The period for the potential filing of a request for rehearing has not yet
expired, but to date WAPA has not sought rehearing at the FERC. In a separate
but related proceeding, the Company and the United States Executive Agencies on
behalf of KAFB are involved in a PRC case regarding a dispute over the specific
Company tariff language under which the Company provides retail service to KAFB.
The Company agreed to continue to provide service to KAFB after expiration of
the contract, pending resolution of all relevant issues. The parties are
presently pursuing informal settlement discussions with regard to this case. The
Company intends to vigorously defend its position at the PRC.
53
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
3.2 By-laws of Public Service Company of New Mexico With All
Amendments to and including April 7, 2001
15.0 Letter Re: Unaudited Interim Financial Information
b. Reports on Form 8-K:
Report dated and filed February 26, 2001 reporting the Company's Comparative
Operating Statistics for the month of January 2001 and 2000 and the year ended
January 31, 2001 and 2000.
Report dated and filed February 28, 2001 reporting the Company declares
Preferred Dividends.
Report dated and filed March 1, 2001 reporting the Company's year-end earnings
results and press conference transcript.
Report dated and filed March 20, 2001 reporting the Company's Comparative
Operating Statistics for the month of February 2001 and 2000 and the year ended
February 28, 2001 and 2000.
Report dated and filed March 27, 2001 reporting the Company raises earnings
forecast for the first quarter.
Report dated and filed April 11, 2001 reporting the Company's Board amends
Articles and Bylaws to reflect changes in State law, renames the planned holding
company as "PNM Resources, Inc."
Report dated and filed April 11, 2001 reporting the Company's "Transforming
Ideas Into Results" 2000 Annual Report to shareholders.
Report dated and filed April 12, 2001 reporting the Company's Comparative
Operating Statistics for the month of March 2001 and 2000 and the year ended
March 31, 2001 and 2000.
Report dated and filed April 16, 2001 reporting the Company hosts first quarter
2001 earnings conference call.
Report dated and filed April 18, 2001 reporting the Company declares common and
preferred stock dividends.
Report dated and filed April 18, 2001 reporting the Company's quarter ended
March 31, 2001 Earnings Announcement and Consolidated Statement of Earnings.
Report dated and filed May 2, 2001 reporting the Company's sustainable growth
underlies record earnings.
54
b. Reports on Form 8-K: (Continued)
Report dated and filed May 2, 2001 reporting the Company's slide presentation
"Transforming Ideas Into Results" delivered by the Company's Chairman, President
and Chief Executive Officer, Jeff Sterba.
55
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: May 15, 2001 /s/ John R. Loyack
---------------------------------------------
John R. Loyack
Vice President, Corporate Controller
and Chief Accounting Officer
(Officer duly authorized to sign this report)
56