Securities and Exchange Commission
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 1-4473
ARIZONA PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
Arizona 86-0011170
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (602) 250-1000
(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 [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Number of shares of common stock, $2.50 par value,
outstanding as of August 13, 2002: 71,264,947
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND
(b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE
FORMAT.
Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
ALJ - administrative law judge
APSES - APS Energy Services Company, Inc., a subsidiary of Pinnacle West
CC&N - Certificate of Convenience and Necessity
Citizens - Citizens Communications Company
Company - Arizona Public Service Company
EITF - Emerging Issues Task Force
ERMC - Pinnacle West's Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
GAAP - Generally accepted accounting principles in the United States
ISO - California Independent System Operator
March 2002 10-Q - Arizona Public Service Company Quarterly Report on Form 10-Q
for the fiscal quarter ended March 31, 2002
MW - megawatt, one million watts
MWh - megawatt hours
Native Load - retail and wholesale sales supplied under traditional cost-based
rate regulation
1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation, parent company of the Company
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of
Pinnacle West
PG&E - PG&E Corp.
PX - California Power Exchange
Rules - ACC retail electric competition rules
SCE - Southern California Edison
SFAS - Statement of Financial Accounting Standards
SPE - special-purpose entity
System - Non-trading energy related activities
T&D - transmission and distribution
Trading - Energy related activities entered into with the objective of
generating profits on changes in market prices
2001 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 2001
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended June 30,
----------------------------
2002 2001
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Retail segment ....................................................... $ 507,711 $ 739,317
Marketing and trading segment ........................................ 2,369 322,154
----------- -----------
Total ............................................................. 510,080 1,061,471
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Retail segment ....................................................... 116,357 444,543
Marketing and trading segment ........................................ 2,268 227,707
----------- -----------
Total ............................................................. 118,625 672,250
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS ................. 391,455 389,221
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel cost ... 122,945 121,052
Depreciation and amortization ........................................ 99,190 104,643
Income taxes ......................................................... 44,140 42,840
Other taxes .......................................................... 27,625 25,448
----------- -----------
Total ............................................................. 293,900 293,983
----------- -----------
OPERATING INCOME ....................................................... 97,555 95,238
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ......................................................... 2,005 (3,005)
Other income ......................................................... 929 12,547
Other expense ........................................................ (5,630) (5,576)
----------- -----------
Total ............................................................. (2,696) 3,966
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ...................................... 94,859 99,204
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................................... 32,301 31,239
Interest on short-term borrowings .................................... 1,162 1,515
Debt discount, premium and expense ................................... 698 1,006
Capitalized interest ................................................. (3,741) (4,195)
----------- -----------
Total ............................................................. 30,420 29,565
----------- -----------
NET INCOME ............................................................. $ 64,439 $ 69,639
=========== ===========
See Notes to Condensed Financial Statements.
2
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Six Months
Ended June 30,
----------------------------
2002 2001
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Retail segment ....................................................... $ 891,452 $ 1,152,124
Marketing and trading segment ........................................ 13,062 674,287
----------- -----------
Total ............................................................. 904,514 1,826,411
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Retail segment ....................................................... 184,643 574,170
Marketing and trading segment ........................................ 12,367 478,885
----------- -----------
Total ............................................................. 197,010 1,053,055
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS ................. 707,504 773,356
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel cost ... 232,266 235,593
Depreciation and amortization ........................................ 196,812 208,339
Income taxes ......................................................... 65,274 86,408
Other taxes .......................................................... 54,376 50,744
----------- -----------
Total ............................................................. 548,728 581,084
----------- -----------
OPERATING INCOME ....................................................... 158,776 192,272
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ......................................................... 2,370 (1,785)
Other income ......................................................... 3,859 13,276
Other expense ........................................................ (9,219) (9,711)
----------- -----------
Total ............................................................. (2,990) 1,780
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ...................................... 155,786 194,052
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................................... 64,038 63,820
Interest on short-term borrowings .................................... 2,299 2,476
Debt discount, premium and expense ................................... 1,340 1,335
Capitalized interest ................................................. (8,093) (7,824)
----------- -----------
Total ............................................................. 59,584 59,807
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE ........................................ 96,202 134,245
Cumulative Effect of a Change in Accounting for Derivatives -
net of income tax benefit of $1,793 ................................ -- (2,755)
----------- -----------
NET INCOME ............................................................. $ 96,202 $ 131,490
=========== ===========
See Notes to Condensed Financial Statements.
3
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended June 30,
----------------------------
2002 2001
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Retail segment ....................................................... $ 2,301,416 $ 2,764,355
Marketing and trading segment ........................................ 87,479 1,376,933
----------- -----------
Total ............................................................. 2,388,895 4,141,288
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Retail segment ....................................................... 837,661 1,397,497
Marketing and trading segment ........................................ 46,937 1,120,736
----------- -----------
Total ............................................................. 884,598 2,518,233
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS ................. 1,504,297 1,623,055
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel cost ... 462,234 452,876
Depreciation and amortization ........................................ 409,366 425,024
Income taxes ......................................................... 162,506 203,033
Other taxes .......................................................... 104,709 99,497
----------- -----------
Total ............................................................. 1,138,815 1,180,430
----------- -----------
OPERATING INCOME ....................................................... 365,482 442,625
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ......................................................... 4,659 2,358
Other income ......................................................... 9,860 18,602
Other expense ........................................................ (19,368) (25,472)
----------- -----------
Total ............................................................. (4,849) (4,512)
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ...................................... 360,633 438,113
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................................... 126,336 132,306
Interest on short-term borrowings .................................... 4,230 4,811
Debt discount, premium and expense ................................... 2,655 2,595
Capitalized interest ................................................. (15,233) (13,812)
----------- -----------
Total ............................................................. 117,988 125,900
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE ........................................ 242,645 312,213
Cumulative Effect of Change in Accounting for Derivatives -
net of income tax benefit of $8,099 and $1,793 ..................... (12,446) (2,755)
----------- -----------
NET INCOME ............................................................. $ 230,199 $ 309,458
=========== ===========
See Notes to Condensed Financial Statements
4
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Dollars in Thousands)
June 30, December 31,
2002 2001
----------- -----------
(Unaudited)
UTILITY PLANT:
Electric plant in service and held for future use ................ $ 8,134,802 $ 7,935,206
Less accumulated depreciation and amortization ................... 3,383,422 3,287,333
----------- -----------
Total ......................................................... 4,751,380 4,647,873
Construction work in progress .................................... 308,425 321,305
Intangible assets, net of accumulated amortization ............... 90,446 83,135
Nuclear fuel, net of accumulated amortization .................... 51,661 49,282
----------- -----------
Utility plant - net ........................................... 5,201,912 5,101,595
----------- -----------
INVESTMENTS AND OTHER ASSETS:
Decommissioning trust accounts ................................... 208,641 202,036
Assets from risk management and trading activities - long-term ... 30,620 2,082
Other assets ..................................................... 37,514 76,322
----------- -----------
Total investments and other assets ............................ 276,775 280,440
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents ........................................ 7,776 16,821
Accounts receivable:
Service customers ............................................. 159,564 182,749
Other ......................................................... 208,251 153,988
Allowance for doubtful accounts ............................... (1,450) (3,349)
Accrued utility revenues ......................................... 110,689 76,131
Materials and supplies, at average cost .......................... 82,300 81,215
Fossil fuel, at average cost ..................................... 31,105 27,023
Assets from risk management and trading activities ............... 9,907 10,097
Other ............................................................ 43,047 42,009
----------- -----------
Total current assets .......................................... 651,189 586,684
----------- -----------
DEFERRED DEBITS:
Regulatory assets ................................................ 291,473 342,383
Unamortized debt issue costs ..................................... 15,319 13,163
Other ............................................................ 52,862 42,789
----------- -----------
Total deferred debits ......................................... 359,654 398,335
----------- -----------
TOTAL ASSETS .................................................. $ 6,489,530 $ 6,367,054
=========== ===========
See Notes to Condensed Financial Statements.
5
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Dollars in Thousands)
June 30, December 31,
2002 2001
----------- -----------
(Unaudited)
CAPITALIZATION:
Common stock .......................................................... $ 178,162 $ 178,162
Additional paid-in capital ............................................ 1,246,804 1,246,804
Retained earnings ..................................................... 801,491 790,289
Accumulated other comprehensive loss .................................. (36,092) (64,565)
----------- -----------
Common stock equity ................................................ 2,190,365 2,150,690
Long-term debt less current maturities ................................ 2,199,837 1,949,074
----------- -----------
Total capitalization ............................................... 4,390,202 4,099,764
----------- -----------
CURRENT LIABILITIES:
Commercial paper ...................................................... 198,000 171,162
Current maturities of long-term debt .................................. 451 125,451
Accounts payable ...................................................... 82,022 98,959
Accrued taxes ......................................................... 157,385 107,595
Accrued interest ...................................................... 41,504 41,043
Customer deposits ..................................................... 33,317 28,664
Deferred income taxes ................................................. 3,244 3,244
Liabilities from risk management and trading activities ............... 21,811 21,840
Other ................................................................. 73,991 117,770
----------- -----------
Total current liabilities .......................................... 611,725 715,728
----------- -----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ................................................. 1,011,032 1,023,079
Liabilities from risk management and trading activities - long-term ... 46,996 95,159
Unamortized gain - sale of utility plant .............................. 61,772 64,060
Customer advances for construction .................................... 67,598 69,293
Other ................................................................. 300,205 299,971
----------- -----------
Total deferred credits and other ................................... 1,487,603 1,551,562
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 12)
TOTAL LIABILITIES AND EQUITY ....................................... $ 6,489,530 $ 6,367,054
=========== ===========
See Notes to Condensed Financial Statements.
6
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months
Ended June 30,
------------------------
2002 2001
--------- ---------
(Dollars in Thousands)
Cash Flows from Operating Activities:
INCOME BEFORE ACCOUNTING CHANGE ...................................... $ 96,202 $ 134,245
Items not requiring cash:
Depreciation and amortization ...................................... 196,812 208,339
Nuclear fuel amortization .......................................... 15,214 14,178
Deferred income taxes - net ........................................ (30,722) (27,350)
Mark-to-market gains - trading ..................................... -- (92,990)
Mark-to-market (gains) losses - system ............................. (6,697) 8,030
Changes in certain current assets and liabilities:
Accounts receivable - net .......................................... (31,642) 172,697
Accrued utility revenues ........................................... (34,558) (30,768)
Materials, supplies and fossil fuel ................................ (5,167) (14,090)
Other current assets ............................................... (1,038) (1,212)
Accounts payable ................................................... (13,522) (103,888)
Accrued taxes ...................................................... 49,790 90,383
Accrued interest ................................................... 461 (5,565)
Other current liabilities .......................................... (39,126) (39,089)
Increase in regulatory assets ........................................ (5,992) (7,447)
Changes in risk management trading investments - at cost ............. (24,030) 22,541
Other net long term assets ........................................... (15,768) (1,955)
Other net long term liabilities ...................................... (964) 45,572
--------- ---------
Net cash flow provided by operating activities ......................... 149,253 371,631
--------- ---------
Cash Flows from Investing Activities:
Trust fund for bond redemption ....................................... -- (72,370)
Capital expenditures ................................................. (253,829) (222,548)
Capitalized interest ................................................. (8,093) (7,824)
Other ................................................................ 38,808 1,855
--------- ---------
Net cash flow used for investing activities ...................... (223,114) (300,887)
--------- ---------
Cash Flows from Financing Activities:
Issuance of long-term debt ........................................... 369,930 --
Short-term borrowings - net .......................................... 26,838 79,900
Dividends paid on common stock ....................................... (85,000) (85,000)
Repayment and reacquisition of long-term debt ........................ (246,952) (58,273)
--------- ---------
Net cash flow provided by (used for) financing activities ........ 64,816 (63,373)
--------- ---------
Net increase (decrease) in cash and cash equivalents ................... (9,045) 7,371
Cash and cash equivalents at beginning of period ....................... 16,821 2,609
--------- ---------
Cash and cash equivalents at end of period ............................. $ 7,776 $ 9,980
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) .......................... $ 57,726 $ 63,932
Income taxes ....................................................... $ 48,943 $ 25,760
See Notes to Condensed Financial Statements.
7
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. Our unaudited condensed financial statements reflect all adjustments which
we believe are necessary for the fair presentation of our financial position and
results of operations for the periods presented. These adjustments are of a
normal recurring nature with the exception of the cumulative effect of a change
in accounting for derivatives (see Note 10). We suggest that these condensed
financial statements and notes to condensed financial statements be read along
with the financial statements and notes to financial statements included in our
2001 10-K.
2. Weather conditions cause significant seasonal fluctuations in our revenues.
Consequently, results for interim periods do not necessarily represent results
to be expected for the year.
3. We are a wholly-owned subsidiary of Pinnacle West.
4. On March 1, 2002, we issued $375 million of 6.5% Notes due 2012. On April
15, 2002, we redeemed $122 million of our First Mortgage Bonds, 8.75% Series due
2024. On March 15, 2002, we redeemed at maturity $125 million of our First
Mortgage Bonds, 8.125% Series due 2002. The above items represent the primary
changes in capitalization for the six months ended June 30, 2002.
5. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
OVERVIEW. On September 21, 1999, the ACC approved Rules that provide a
framework for the introduction of retail electric competition in Arizona. On
September 23, 1999, the ACC approved a comprehensive settlement agreement among
us and various parties related to the implementation of retail electric
competition in Arizona. Under the Rules, as modified by the 1999 Settlement
Agreement, we are required to transfer all of our competitive electric assets
and services to an unaffiliated party or parties or to a separate corporate
affiliate or affiliates no later than December 31, 2002. Consistent with that
requirement, we have been addressing the legal and regulatory requirements
necessary to complete the transfer of our generation assets to Pinnacle West
Energy on or before that date.
In January 2002, the ACC opened a "generic" docket to "determine if changed
circumstances require the [ACC] to take another look at electric restructuring
in Arizona." On June 17, 2002, hearings began on various issues ("Track A
Issues") in the consolidated docket. On July 23, 2002, an ACC ALJ issued a
recommended order on Track A Issues recommending, among other things, that our
ability to transfer our generation assets be stayed until at least July 1, 2004.
On August 1, 2002, we filed exceptions to the recommended order stating that it
is unreasonable and unlawful. The ACC will hold an open meeting on August 27,
2002 to consider Track A Issues. These matters are discussed in more detail
below.
8
1999 SETTLEMENT AGREEMENT. The following are the major provisions of the
1999 Settlement Agreement, as approved:
* We have reduced, and will reduce, rates for standard-offer service for
customers with loads less than three MW in a series of annual retail
electricity price reductions of 1.5% beginning July 1, 1999 through
July 1, 2003, for a total of 7.5%. The first reduction of
approximately $24 million ($14 million after income taxes) included a
July 1, 1999 retail price decrease of approximately $11 million ($7
million after income taxes) related to a 1996 regulatory agreement.
Based on the price reductions authorized in the 1999 Settlement
Agreement, there were also retail price decreases of approximately $28
million ($17 million after taxes), or 1.5%, effective July 1, 2000;
approximately $27 million ($16 million after taxes), or 1.5%,
effective July 1, 2001; and approximately $28 million ($17 million
after taxes), or 1.5%, effective July 1, 2002. For customers having
loads of three MW or greater, standard-offer rates have been reduced
in varying annual increments that total 5% in the years 1999 through
2002.
* Unbundled rates being charged by us for competitive direct access
service (for example, distribution services) became effective upon
approval of the 1999 Settlement Agreement, retroactive to July 1,
1999, and also became subject to annual reductions beginning January
1, 2000, that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard-offer
and unbundled competitive direct access services until July 1, 2004,
except for the price reductions described above and certain other
limited circumstances. Neither the ACC nor we will be prevented from
seeking or authorizing rate changes prior to July 1, 2004 in the event
of conditions or circumstances that constitute an emergency, such as
an inability to finance on reasonable terms; material changes in our
cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or judicial
decisions, actions or orders.
* We will be permitted to defer for later recovery prudent and
reasonable costs of complying with the Rules, system benefits costs in
excess of the levels included in then-current (1999) rates, and costs
associated with the "provider of last resort" and standard-offer
obligations for service after July 1, 2004. These costs are to be
recovered through an adjustment clause or clauses commencing on July
1, 2004.
* Our distribution system opened for retail access effective September
24, 1999. Customers were eligible for retail access in accordance with
the phase-in adopted by the ACC under the Rules (see "Retail Electric
Competition Rules" below), including an additional 140 MW being made
available to eligible non-residential customers. We opened our
distribution system to retail access for all customers on January 1,
2001.
* Prior to the 1999 Settlement Agreement, we were recovering
substantially all of our regulatory assets through July 1, 2004,
pursuant to a 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that we have demonstrated that our
9
allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value. We will not be
allowed to recover $183 million net present value of the above
amounts. The 1999 Settlement Agreement provides that we will have the
opportunity to recover $350 million net present value through a
competitive transition charge that will remain in effect through
December 31, 2004, at which time it will terminate. The costs subject
to recovery under the adjustment clause described above will be
decreased or increased by any over/under-recovery due to sales volume
variances.
* We will form, or cause to be formed, a separate corporate affiliate or
affiliates and transfer to such affiliate(s) our competitive electric
assets and services at book value as of the date of transfer, and will
complete the transfers no later than December 31, 2002. We will be
allowed to defer and later collect, beginning July 1, 2004,
sixty-seven percent of our costs to accomplish the required transfer
of generation assets to an affiliate. Consistent with that
requirement, we have been addressing the legal and regulatory
requirements necessary to complete the transfer of our generation
assets to Pinnacle West Energy on or before that date. However, as
noted above and discussed in greater detail below, an ACC ALJ has
recommended that our ability to transfer our generation assets be
stayed until at least July 1, 2004.
RETAIL ELECTRIC COMPETITION RULES. The Rules approved by the ACC include
the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by
the ACC, including us.
* Effective January 1, 2001, retail access became available to all our
retail electricity customers.
* Electric service providers that get CC&N's from the ACC can supply
only competitive services, including electric generation, but not
electric transmission and distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
noncompetitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
electric assets and services to an unaffiliated party or parties or to
a separate corporate affiliate or affiliates. Under the 1999
Settlement Agreement, we received a waiver to allow transfer of our
competitive electric assets and services to affiliates no later than
December 31, 2002.
10
Under the 1999 Settlement Agreement, the Rules are to be interpreted and
applied, to the greatest extent possible, in a manner consistent with the 1999
Settlement Agreement. If the two cannot be reconciled, we must seek, and the
other parties to the 1999 Settlement Agreement must support, a waiver of the
Rules in favor of the 1999 Settlement Agreement.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers to
operate in Arizona. We do not believe the ruling affects the 1999 Settlement
Agreement. The 1999 Settlement Agreement was not at issue in the consolidated
cases before the judge. Further, the ACC made findings related to the fair value
of our property in the order approving the 1999 Settlement Agreement. The ACC
and other parties aligned with the ACC have appealed the ruling to the Arizona
Court of Appeals, as a result of which the Superior Court's ruling is
automatically stayed pending further judicial review. In a similar appeal
concerning the issuance of competitive telecommunications CC&N's, the Arizona
Court of Appeals invalidated rates for competitive carriers due to the ACC's
failure to establish a fair value rate base for such carriers. That decision was
upheld by the Arizona Supreme Court.
PROVIDER OF LAST RESORT OBLIGATION. Although the Rules allow retail
customers to have access to competitive providers of energy and energy services,
we are the "provider of last resort" for standard-offer, full-service customers
under rates that have been approved by the ACC. These rates are established
until July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment
of these rates in the event of emergency conditions or circumstances, such as
the inability to secure financing on reasonable terms; material changes in our
cost of service for ACC-regulated services resulting from federal, tribal, state
or local laws; regulatory requirements; or judicial decisions, actions or
orders. Energy prices in the western wholesale market vary and, during the
course of the last two years, have been volatile. At various times, prices in
the spot wholesale market have significantly exceeded the amount included in our
current retail rates. In the event of shortfalls due to unforeseen increases in
load demand or generation or transmission outages, we may need to purchase
additional supplemental power in the wholesale spot market. Unless we are able
to obtain an adjustment of our rates under the emergency provisions of the 1999
Settlement Agreement, there can be no assurance that we would be able to fully
recover the costs of this power.
PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. Commencing on the
transfer of the fossil-fueled generating assets and the receipt of certain
regulatory approvals, Pinnacle West Energy expects to sell its power at
wholesale to Pinnacle West's marketing and trading division, which, in turn, is
expected to sell power to us and to non-affiliated power purchasers. In a filing
with the ACC on October 18, 2001, we requested the ACC to:
* grant us a partial variance from an ACC Rule that would obligate us to
acquire all of our customers' standard-offer, full-service generation
11
requirements from the competitive market (with at least 50% of those
requirements coming from a "competitive bidding" process) starting in
2003; and
* approve as just and reasonable a long-term purchase power agreement
between us and Pinnacle West.
We requested these ACC actions to ensure ongoing reliable service to our
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve our load.
GENERIC DOCKET. In January 2002, the ACC opened a "generic" docket to
"determine if changed circumstances require the [ACC] to take another look at
electric restructuring in Arizona." In February 2002, the ACC docket relating to
our October 2001 filing was consolidated with several other pending ACC dockets,
including the generic docket. On April 19, 2002, we filed a motion in the
consolidated docket addressing the following issues, among others:
* We confirmed our position that whether or not the ACC approved the
matters requested in our October 2001 filing, we would proceed with
the divestiture of our generation assets by the end of 2002, as
legally required.
* We also advised the ACC that whether or not the ACC approved the
matters requested in our October 2001 filing, we would implement a
competitive bidding process later in 2002 to the extent legally
required.
* We noted that Pinnacle West Energy, the affiliate to which we intend
to transfer the generation assets, had committed to an investment of
approximately $1 billion in generating capacity to meet our customer
needs in reliance on the 1999 Settlement Agreement. We further noted
that we have taken numerous actions in reliance on the 1999 Settlement
Agreement and the ACC Rules, including writing off $234 million before
income taxes of prudently incurred costs, reducing retail rates in an
ongoing series of rate reductions, and incurring tens of millions of
dollars in expenses related to the expected generation asset transfer.
We stated that if the ACC elects to reverse course on retail electric
competition or attempts to stay the transfer of our generation assets,
the ACC would be legally required to address just compensation to us
and Pinnacle West Energy, which would include, at a minimum:
* recognizing the transfer to us of all assets that Pinnacle West
Energy constructed to meet our load-serving requirements, and
subsequently including such units in our rate base in accordance
with traditional rate-of-return regulation;
* reversing our $234 million pre-tax write-off and providing for
the recovery of such amounts in future rates; and
* providing for the recovery of all costs incurred as a result of
the transition to competition, including 100 percent of the costs
12
incurred in preparation for divestiture (and not just the
sixty-seven percent of costs permitted under the 1999 Settlement
Agreement).
* We recommended that the ACC confirm whether or not Arizona would
proceed with the transition to a competitive electric market, and
proposed a procedural plan in response to issues identified by the ACC
Staff in a previous report.
On April 26, 2002, the ACC issued a procedural order in which the ACC
stayed the previously-scheduled April 29, 2002 hearing on the matters raised in
our October 2001 ACC filing (see "Proposed Rule Variance and Purchase Power
Agreement" above). On May 2, 2002, the ACC issued a procedural order stating
that hearings would begin on June 17, 2002 on various issues ("Track A Issues"),
including our planned divestiture of generation assets to Pinnacle West Energy
and associated market and affiliate issues.
The procedural order also stated that consideration of the competitive
bidding process (the "Track B Issues") required by the Rules would proceed
concurrently with the Track A Issues. The objectives and process of the Track B
Issues would be determined in one or more meetings of affected parties with a
"target completion date" of October 21, 2002.
On July 11, 2002, we filed a letter with the ACC discussing the
circumstances under which we could support a temporary suspension or stay of
certain Arizona electric competition rules. In our letter, we stated that we
could support a delay of the Rules' mandatory divestiture of generation assets
and competitive procurement requirements if:
* the ACC permits us to end the "bifurcation" of our generation
resources as between ourselves and Pinnacle West Energy by authorizing
the acquisition by us of the Pinnacle West Energy generating
facilities constructed or being constructed to serve us;
* the ACC provides to us any additional debt financing authorization
necessary to accomplish this acquisition; and
* while these assets remain with us serving retail customers, their
inclusion in rates will be subject to ACC review as to their prudence
and as to whether they are "used and useful" just as are our existing
generating plants.
On July 23, 2002 an ACC ALJ issued a recommended order on Track A Issues in
the consolidated docket. Among other things, the ALJ recommends that:
* our ability to transfer our generation assets be stayed until the ACC
determines that the wholesale market is "workably competitive" and
until at least July 1, 2004, at which time the ACC would reassess the
appropriateness and timing of divestiture;
13
* the current requirement that 100 percent of power purchased for
standard-offer service be acquired from the competitive market, with
at least 50 percent through a competitive bid process, be stayed
indefinitely; and
* upon implementation of the outcome of the competitive bidding process
("Track B Issues"), we would acquire, at a minimum, any required power
not produced by our owned generation through a competitive procurement
process developed in the Track B proceeding.
In addition, the ALJ recommended that if we wish to acquire certain
generation assets from Pinnacle West Energy, as discussed in our July 11, 2002
letter to the ACC, we should file appropriate applications on this matter for
ACC consideration.
The ALJ also recommended that the ACC Staff open a rulemaking to review the
Rules in light of the other decisions in the recommended order and that an
Electric Competition Advisory Group be formed to facilitate communication among
the ACC Staff, stakeholders and market participants.
On August 1, 2002, we filed exceptions to the recommended order, stating
that the recommended order, if adopted by the ACC, would be unreasonable and
unlawful because, among other reasons:
* the recommended order's prohibition on our transfer of generation
assets to Pinnacle West Energy would unfairly harm us and Pinnacle
West by bifurcating generation assets between us and Pinnacle West
Energy, even though those assets are devoted to serving our customers;
* the recommended order's prohibition on our transfer of generation
assets to Pinnacle West Energy would constitute a material breach of
the 1999 Settlement Agreement, even though we have fulfilled our
obligations under the 1999 Settlement Agreement, including writing off
$234 million of otherwise recoverable costs, voluntarily reducing
retail rates by some $600 million (to date), and dismissing with
prejudice our pending litigation against the ACC;
* the recommended order does not discuss less onerous alternatives to
breaching the 1999 Settlement Agreement, such as consideration of the
Purchase Power Agreement proposed by us in our October 18, 2001 filing
with the ACC or our acquisition of certain Pinnacle West Energy
generation assets, as outlined in our July 11, 2002 letter to the ACC;
* the recommended order's finding that we have wholesale market power in
certain Arizona geographical areas is not supported by the evidence
or, at worst, the ACC should make no finding on the issue of market
power; and
* the "generic proceedings" giving rise to the recommended order do not
and have not complied with Arizona law as applicable to the amendment
or rescission of the ACC order associated with the 1999 Settlement
Agreement.
14
The ACC will hold an open meeting on August 27, 2002 to consider Track A
Issues.
We cannot predict the outcome of the consolidated docket or its effect on
the existing Rules or the 1999 Settlement Agreement.
FEDERAL
In June 2001, the FERC adopted a price mitigation plan that constrains the
price of electricity in the wholesale spot electricity market in the western
United States. The plan, which has a price cap of approximately $90 per MWh,
remains in effect until September 30, 2002. FERC has now adopted a final price
cap of $250 per MWh, which will become effective as of October 1, 2002.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking Standard
Market Design for wholesale electric markets. We are reviewing the proposed
rulemaking and cannot currently predict what, if any, impact there may be to the
Company if the FERC adopts the proposed rule.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete in the new
regulatory environment.
6. Nuclear Insurance
The Palo Verde 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 accumulated funds, we could be
assessed retrospective premium 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 incident. Based upon our interest
in the three Palo Verde units, our maximum potential assessment per incident for
all three units is approximately $77 million, with an annual payment limitation
of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. We have also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
15
7. Business Segments
We have two principal business segments (determined by products, services
and the regulatory environment), which consist of our regulated retail
electricity business, regulated traditional wholesale electricity business, and
related activities (electric retail business segment) and our competitive
business activities (marketing and trading business segment). Our electric
retail business segment includes activities related to electricity transmission
and distribution, as well as electricity generation. Our marketing and trading
business segment includes activities related to wholesale marketing and trading.
During 2001, we transferred most of our marketing and trading activities,
including all related assets and liabilities, to Pinnacle West (see Note 14).
Financial data for the business segments follows (dollars in millions):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
------------------- ------------------- -------------------
2002 2001 2002 2001 2002 2001
------- ------- ------- ------- ------- -------
Operating Revenues:
Electric retail $ 508 $ 739 $ 892 $ 1,152 $ 2,301 $ 2,764
Marketing and trading 2 322 13 674 88 1,377
------- ------- ------- ------- ------- -------
Total $ 510 $ 1,061 $ 905 $ 1,826 $ 2,389 $ 4,141
======= ======= ======= ======= ======= =======
Income Before
Accounting Change:
Electric retail $ 64 $ 13 $ 96 $ 16 $ 218 $ 157
Marketing and trading -- 57 -- 118 24 155
------- ------- ------- ------- ------- -------
Total $ 64 $ 70 $ 96 $ 134 $ 242 $ 312
======= ======= ======= ======= ======= =======
8. Accounting Matters
On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." We have no goodwill recorded and have separately disclosed
other intangible assets in our balance sheets. This new standard has no material
impact on our financial statements, and the required disclosures are provided in
Note 13.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the accounting and reporting provisions for the disposal of
a segment of a business. This standard did not impact our financial statements
at adoption.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which we will adopt January 1, 2003. The standard
requires the fair value of asset retirement obligations to be recorded as a
liability, along with an offsetting plant asset, when the obligation is
incurred. Accretion of the liability due to the passage of time will be an
operating expense and the capitalized cost will be depreciated over the useful
life of the long-lived asset.
16
We have not yet determined the impact of the new standard on our financial
statements. We determined that we have asset retirement obligations for our
nuclear facilities (nuclear decommissioning) and certain other fossil
generation, transmission, and distribution assets. Upon adoption, we will record
the retirement obligations and the related plant assets and accumulated
depreciation. The impact of these adjustments will likely be different than the
removal costs currently reflected in our financial statements for assets that
have an asset retirement obligation. For our non-regulated operations, the
impact of adopting this new standard will be reflected in earnings as a
cumulative effect of a change in accounting principle. We are currently
evaluating our ability to recover the transition costs and ongoing current
period costs of SFAS No. 143 in rates for our regulated operations. If such
costs are expected to be recoverable in rates, we would recognize a regulatory
asset or regulatory liability upon the adoption of SFAS No. 143 rather than a
cumulative effect adjustment to earnings.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" which supersedes previous guidance for reporting gains and losses
from extinguishment of debt and accounting for leases, among other things. The
portion of the statement relating to the early extinguishment of debt is
effective for us beginning in 2003. We do not believe the adoption of this
statement will have a material impact on our financial statements.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." The standard requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The guidance should be applied prospectively to exit or disposal activities
initiated after December 31, 2002.
In 2001, the American Institute of Certified Public Accountants issued an
exposure draft of a proposed Statement of Position, "Accounting for Certain
Costs Related to Property, Plant, and Equipment." This proposed Statement of
Position, which would be effective for us in 2004, would create a project
timeline framework for capitalizing costs related to property, plant and
equipment construction. It would require that property, plant and equipment
assets be accounted for at the component level, and require administrative and
general costs incurred in support of capital projects to be expensed in the
current period. The American Institute of Certified Public Accountants plans to
issue the final Statement of Position in the fourth quarter of 2002.
In June 2002, the FASB's EITF finalized certain guidance related to energy
trading activities in EITF 02-3 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities." The new guidance, which is effective
July 1, 2002, requires that all energy trading activities within the scope of
EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities," be presented on a net basis in revenues and that prior
period amounts should be restated to conform to the consensus. We will make this
presentation change in the third quarter of 2002. The impact on our marketing
and trading segment would result in equivalent decreases in revenues and
purchased power (gross margin would not be affected) for the three-, six-, and
twelve-month periods ended June 30, 2002 and 2001 as follows (dollars in
millions before income taxes):
17
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
-------- -------- --------
2002 $ -- $ -- $ 3
2001 $ 91 $ 196 $ 643
9. Off-Balance Sheet Financing
In 1986, we entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. In July 2002, the
FASB issued an exposure draft related to SPEs. It is expected that the FASB will
issue final guidance on accounting for SPEs later this year with an immediate
effective date for newly-created entities and for all other entities as of the
beginning of the first fiscal period beginning April 1, 2003. We are currently
evaluating the impacts of the exposure draft and we may be required to
consolidate the Palo Verde SPEs in our financial statements. If consolidation
were required, the assets and liabilities of the SPEs that relate to the
sale-leaseback transactions would be reflected on our condensed balance sheet at
fair value. We are also evaluating the impact of including the related fair
value of assets and liabilities. The secured lease obligation bonds that are not
reflected on our condensed balance sheet at June 30, 2002 are approximately $285
million. The rating agencies have already considered this debt when evaluating
our credit ratings. This is our only significant off-balance sheet financing
activity.
10. Derivative Instruments
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We employ established procedures to manage risks associated with these market
fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. We use cash flow hedges to limit our exposure to cash flow variability
on forecasted transactions. Hedge effectiveness is related to the degree to
which the derivative contract and the hedged item are correlated. It is measured
based on the relative changes in fair value between the derivative contract and
the hedged item over time. We exclude the time value of certain options from our
assessment of hedge effectiveness. Any change in the fair value resulting from
ineffectiveness is recognized immediately in net income.
On January 1, 2001, we recorded a $3 million after-tax loss in net income
and a $65 million after-tax gain in equity (as a component of other
comprehensive income), both as a cumulative effect of a change in accounting
principle. The gain resulted from unrealized gains on cash flow hedges.
18
In June 2001, the FASB issued new guidance related to electricity
contracts. The effective date of this new guidance was July 1, 2001. As of July
1, 2001, we recorded an additional $12 million after-tax loss in net income and
an additional $8 million after-tax gain in equity (as a component of other
comprehensive income), as a result of adopting the new guidance related to
electricity contracts. The loss resulted primarily from electricity options
contracts. The gain resulted from unrealized gains on cash flow hedges. The
impact of the new guidance is reflected in net income and other comprehensive
income as a cumulative effect of a change in accounting principle.
In December 2001, the FASB issued revised guidance on the accounting for
electricity contracts with option characteristics and the accounting for
contracts that combine a forward contract and a purchased option contract. The
effective date for the revised guidance was April 1, 2002. The impact of this
guidance was immaterial to our financial statements.
The change in derivative fair value included in the condensed statements of
income for the three, six and twelve months ended June 30, 2002 and 2001 are
comprised of the following (dollars in thousands):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
---------------------- ---------------------- ----------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Gains (losses) on the
ineffective portion of
derivatives qualifying
for hedge accounting $ 3,227 $ (1,419) $ 3,115 $ (6,184) $ 928 $ (6,184)
Losses from the
discontinuance of
cash flow hedges (1,857) (8,325) (3,157) (8,324) (4,358) (8,324)
Prior period mark-to-
market losses realized
upon delivery of
commodities 2,926 85 6,739 6,478 26,208 6,478
-------- -------- -------- -------- -------- --------
Total pretax gain (loss) $ 4,296 $ (9,659) $ 6,697 $ (8,030) $ 22,778 $ (8,030)
======== ======== ======== ======== ======== ========
As of June 30, 2002, the maximum length of time over which we are hedging
our exposure to the variability in future cash flows for forecasted transactions
is thirty months. During the twelve months ending June 30, 2003, we estimate
that a net loss of $16 million before income taxes will be reclassified from
accumulated other comprehensive loss as an offset to the effect on earnings of
market price changes for the related hedged transactions.
19
11. Comprehensive Income
Components of comprehensive income for the three, six and twelve months
ended June 30, 2002 and 2001, are as follows (dollars in thousands):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
----------------------- ----------------------- ------------------------
2002 2001 2002 2001 2002 2001
--------- --------- --------- --------- --------- ---------
Net income $ 64,439 $ 69,639 $ 96,202 $ 131,490 $ 230,199 $ 309,458
--------- --------- --------- --------- --------- ---------
Other comprehensive
income (loss):
Minimum pension
liability, net of tax -- -- -- -- (966) --
Cumulative effect of
change in
accounting for
derivatives, net of
tax -- -- -- 64,700 7,801 64,700
Unrealized gains
(losses) on
derivative
instruments, net of
tax(a) 2,089 (87,475) 23,851 (94,134) 15,344 (94,134)
Reclassification of
net realized (gains)
losses to income,
net of tax(b) 1,076 (1,862) 4,622 (22,478) (6,359) (22,478)
--------- --------- --------- --------- --------- ---------
Total other
comprehensive
income (loss) 3,165 (89,337) 28,473 (51,912) 15,820 (51,912)
--------- --------- --------- --------- --------- ---------
Comprehensive income (loss) $ 67,604 $ (19,698) $ 124,675 $ 79,578 $ 246,019 $ 257,546
========= ========= ========= ========= ========= =========
(a) These amounts primarily include unrealized gains and losses on contracts
used to hedge our forecasted gas requirements to serve native load.
(b) These amounts primarily include the reclassification of unrealized gains
and losses to realized for contracts that delivered during the period.
20
12. Commitments and Contingencies
California Energy Market Issues and Refunds in the Pacific Northwest
In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the ISO and PX provide necessary historical data. The FERC also
ordered an evidentiary proceeding to discuss and evaluate possible refunds for
the Pacific Northwest. The administrative law judge at the FERC in charge of
that evidentiary proceeding made an initial finding that no refunds were
appropriate. The Pacific Northwest issues will now be addressed by the FERC
Commissioners. Although the FERC has not yet made a final ruling in the Pacific
Northwest matter or calculated the specific refund amounts due in California, we
do not expect that the resolution of these issues, as to the amounts alleged in
the proceedings, will have a material adverse impact on our financial position,
results of operations or liquidity.
SCE and PG&E have publicly disclosed that their liquidity has been
materially and adversely affected because of, among other things, their
inability to pass on to ratepayers the prices each has paid for energy and
ancillary services procured through the PX and the ISO. PG&E filed for
bankruptcy protection in 2001.
We are closely monitoring developments in the California energy market and
the potential impact of these developments on us. We have evaluated, among other
things, SCE's role as a Palo Verde and Four Corners participant; our
transactions with the PX and the ISO; contractual relationships with SCE and
PG&E; and marketing and trading exposures. Based on our evaluations, we do not
believe the foregoing matters will have a material adverse affect on our
financial position and liquidity. We cannot predict with certainty, however, the
impact that any future resolution or attempted resolution, of the California
energy market situation may have on us or the regional energy market in general.
CALIFORNIA ENERGY MARKET LITIGATION. On March 19, 2002, the State of
California filed a complaint with the FERC alleging that wholesale sellers of
power and energy, including Pinnacle West, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the
present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET. AL., Docket
No. EL02-71-000. The complaint requests the FERC to require the wholesale
sellers to refund any rates that are "found to exceed just and reasonable
levels." This complaint has been dismissed by FERC. In addition, the State of
California and others have filed various claims, which have now been
consolidated, against several power suppliers to California alleging antitrust
violations. WHOLESALE ELECTRICITY ANTITRUST CASES I AND II, Superior Court in
and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two
of the suppliers who were named as defendants in those matters, Reliant Energy
Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP
(and other Duke entities), filed cross-claims against various other participants
in the California PX and ISO markets, including us, attempting to expand those
matters to such other participants. We have not yet filed a responsive pleading
in the matter, but we believe the claims by Reliant and Duke as they relate to
us are without merit.
We were also named in a lawsuit regarding wholesale contracts in
California. JAMES MILLAR, ET AL. V. ALLEGHENY ENERGY SUPPLY, ET AL., United
States District Court in and for the District of Northern California, Case No.
21
C02-2855 EMC. The complaint alleges basically that the contracts entered into
were the result of an unfair and unreasonable market. The California PX has
filed a lawsuit against the State of California regarding the seizure of forward
contracts and the State has filed a cross complaint against us. CAL PX V. THE
STATE OF CALIFORNIA Superior Court in and for the County of Sacramento, JCCP No.
4203. Various preliminary motions are being filed and we cannot currently
predict the outcome of this matter. The "United States Justice Foundation" is
suing numerous wholesale energy contract suppliers to California, including
Pinnacle West, as well as the California Department of Water Resources, based
upon an alleged conflict of interest arising from the activities of a consultant
for Edison International who also negotiated long-term contracts for the
California Department of Water Resources. MCCLINTOCK, ET AL. V. YUDHRAJA,
Superior Court in and for the County of Los Angeles, Case No. GC 029447. The
California Attorney General has indicated that an investigation by his office
did not find evidence of improper conduct by the consultant. We believe the
claims against us in the lawsuits mentioned in this paragraph are without merit
and will have no material adverse impact on our financial position, results of
operations or liquidity.
Power Service Agreement
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised us that it believes we have overcharged Citizens by over $50 million
under a power service agreement. We believe that our charges under the agreement
were fully in accordance with the terms of the agreement. In addition, in
testimony filed with the ACC on March 13, 2002, Citizens acknowledged that,
based on its review, "if Citizens filed a complaint with FERC, it probably would
lose the central issue in the contract interpretation dispute." We terminated
the power service agreement with Citizens effective July 15, 2001. In
replacement of the power service agreement, Pinnacle West and Citizens entered
into a power sale agreement under which Pinnacle West will supply Citizens with
specified amounts of electricity and ancillary services through May 31, 2008.
This new agreement does not address issues previously raised by Citizens with
respect to charges under the original power service agreement through June 1,
2001.
13. Intangible Assets
On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." The Company's gross intangible assets (which are primarily
software) were $185 million at June 30, 2002 and $170 million at December 31,
2001. The related accumulated amortization was $95 million at June 30, 2002 and
$87 million at December 31, 2001. Amortization expense for the three-month
period ended June 30 was $5 million in 2002 and 2001. Amortization expense for
the six-month period ended June 30 was $9 million in 2002 and $10 million in
2001. Amortization expense for the twelve-month period ended June 30 was $20
million in 2002 and $21 million in 2001. Estimated amortization expense on
existing intangible assets over the next five years is $16 million in 2002, $14
million in 2003, $14 million in 2004, $12 million in 2005 and $11 million in
2006.
22
14. Related Party Transactions
During 2001, we transferred most of our marketing and trading activities to
Pinnacle West, which approximated $219 million in assets and $149 million in
liabilities. From time to time, we enter into transactions with Pinnacle West or
Pinnacle West's subsidiaries. The following table summarizes the amounts
included in the income statements and balance sheets related to transactions
with affiliated companies (dollars in millions):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
----------------- ----------------- -----------------
2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------
Electric operating revenues:
Pinnacle West -
marketing and trading $ 30 $ -- $ 47 $ -- $ 97 $ --
APSES -- -- -- 5 10 31
------ ------ ------ ------ ------ ------
Total $ 30 $ -- $ 47 $ 5 $ 107 $ 31
====== ====== ====== ====== ====== ======
Purchased power and fuel costs:
Pinnacle West -
marketing and trading $ -- $ 14 $ 6 $ 26 $ 30 $ 26
Pinnacle West Energy -- -- -- -- 14 --
------ ------ ------ ------ ------ ------
Total $ -- $ 14 $ 6 $ 26 $ 44 $ 26
====== ====== ====== ====== ====== ======
As of As of
June 30, December 31,
-------- ------------
2002 2001
------ ------
Accounts receivable - other:
Pinnacle West - marketing
and trading $ 158 $ 76
Pinnacle West -- 24
APSES -- 13
Pinnacle West Energy 1 2
------ ------
Total $ 159 $ 115
====== ======
Accounts payable:
Pinnacle West - marketing
and trading $ 27 $ 21
Pinnacle West 8 36
Pinnacle West Energy 1 2
------ ------
Total $ 36 $ 59
====== ======
23
15. Other Income and Other Expense
The following table provides detail of other income and other expense for
the three, six and twelve months ended June 30, 2002 and 2001 (dollars in
thousands):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
---------------------- ---------------------- ----------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Other income:
Environmental insurance
recovery $ -- $ 10,947 $ -- $ 10,947 $ 1,402 $ 10,947
Investment gains - net -- -- 1,565 -- 633 --
Interest income 481 1,371 1,426 1,703 4,727 5,469
Miscellaneous 448 229 868 626 3,098 2,186
-------- -------- -------- -------- -------- --------
Total other income $ 929 $ 12,547 $ 3,859 $ 13,276 $ 9,860 $ 18,602
======== ======== ======== ======== ======== ========
Other expense:
Investment losses - net $ (222) $ (2,568) $ -- $ (2,423) $ -- $ (4,008)
Non-operating costs (a) (4,567) (1,479) (6,874) (4,623) (15,653) (14,460)
Miscellaneous (841) (1,529) (2,345) (2,665) (3,715) (7,004)
-------- -------- -------- -------- -------- --------
Total other expense $ (5,630) $ (5,576) $ (9,219) $ (9,711) $(19,368) $(25,472)
======== ======== ======== ======== ======== ========
(a) Primarily includes below the line utility costs.
24
ARIZONA PUBLIC SERVICE COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
INTRODUCTION
In this section, we explain our results of operations, general financial
condition, and outlook including:
* the changes in our earnings for the three, six and twelve months ended
June 30, 2002 and 2001;
* the effects of regulatory agreements and developments on our results
and outlook;
* our capital needs, liquidity and capital resources;
* our business outlook; and
* our management of market risks.
We suggest this section be read along with the 2001 10-K. Throughout this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, we refer to specific "Notes" in the Notes to Condensed Financial
Statements in this report. These Notes add further details to the discussion.
OVERVIEW OF OUR BUSINESS
We are an electric utility that provides either retail or wholesale
electric service to substantially all of the state of Arizona, with the major
exceptions of the Tucson metropolitan area and about one-half of the Phoenix
metropolitan area. Electricity is provided through a distribution system owned
by us. We also generate and, through Pinnacle West's marketing and trading
division, sell and deliver electricity to wholesale customers in the western
United States. Pinnacle West owns all of our outstanding stock.
We are required to transfer our competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, we have been addressing the legal and regulatory
requirements necessary to complete the transfer of our generation assets to
Pinnacle West Energy before that date. As we discuss in greater detail in Note
5, on July 23, 2002, an ACC ALJ issued a recommended order recommending, among
other things, that our ability to transfer our generation assets be stayed until
at least July 1, 2004.
BUSINESS SEGMENTS
We have two principal business segments (determined by products, services
and the regulatory environment), which consist of our regulated retail
electricity business, regulated traditional wholesale electricity business, and
25
related activities (electric retail business segment) and our competitive
business activities (marketing and trading business segment). Our electric
retail business segment includes activities related to electricity transmission
and distribution, as well as electricity generation. Our marketing and trading
business segment includes activities related to wholesale marketing and trading.
During 2001, we transferred most of our marketing and trading activities to
Pinnacle West (see Note 14).
The following table summarizes net income by business segment for the
three, six and twelve months ended June 30, 2002 and the comparable prior year
periods (dollars in millions, unaudited):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
----------------- ----------------- ------------------
2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------
Electric retail $ 64 $ 13 $ 96 $ 16 $ 218 $ 157
Marketing and trading -- 57 -- 118 24 155
------ ------ ------ ------ ------ ------
Income before accounting
change 64 70 96 134 242 312
Cumulative effect of change
in accounting - net of
income taxes -- -- -- (3) (12) (3)
------ ------ ------ ------ ------ ------
Net income $ 64 $ 70 $ 96 $ 131 $ 230 $ 309
====== ====== ====== ====== ====== ======
We recorded the cumulative effects of a change in accounting for
derivatives related to our adoption in 2001 of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities."
EARNINGS VARIANCE EXPLANATIONS
Throughout these explanations, we refer to "gross margin." With respect to
our electric retail segment and marketing and trading segment, gross margin
refers to electric operating revenues less purchased power and fuel costs.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED JUNE 30, 2002 COMPARED WITH
THREE-MONTH PERIOD ENDED JUNE 30, 2001
Our net income for the three months ended June 30, 2002 was $64 million
compared with $70 million for the same period in the prior year. The
period-to-period decrease was primarily the result of our transfer of marketing
and trading activities to Pinnacle West in 2001, substantially offset by higher
retail earnings. The retail comparison was favorably impacted by lower
replacement costs for power plant outages, lower costs for purchased power and
gas related to lower market prices, customer growth and higher average usage per
customer, partially offset by the effects of milder weather. Also, there was
lower other income, partially offset by decreased depreciation and amortization
expense.
26
The major factors that increased (decreased) net income were as follows (dollars
in millions):
Increase
(Decrease)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages $ 58
Lower purchased power and fuel costs related to lower prices,
net of hedge management sales 40
Effects of milder weather on retail sales (16)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 12
Retail price reductions effective July 1, 2001 (7)
Lower purchased power costs related to 2001 generation reliability
program 6
Miscellaneous factors - net 3
-------
Net increase in electric retail segment gross margin 96
Marketing and trading segment gross margin:
Decrease in marketing and trading segment margin resulting
from our transfer of marketing and trading activities to
Pinnacle West in 2001 (94)
-------
Total increase in the electric retail and the marketing and trading
segments' gross margins 2
Higher operations and maintenance expense primarily related to
increased overhaul costs and increased employee benefit costs,
partially offset by lower costs for generation reliability outages (2)
Lower depreciation and amortization expense primarily related to lower
regulatory asset amortization 5
Lower other income (12)
Miscellaneous items, net (3)
-------
Decrease in income before income taxes (10)
Lower income taxes primarily due to lower pretax income 4
-------
Decrease in net income $ (6)
=======
Electric Retail Segment Gross Margin
Revenues related to our regulated retail and wholesale electricity
businesses were $232 million lower in the three-month period ended June 30,
2002, compared to the same period in the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($54 million);
* decreased revenues related to retail load hedge management wholesale
sales, as a result of lower sales volumes and lower prices ($167
million);
27
* decreased retail revenues related to milder weather ($26 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($21 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($7 million); and
* other miscellaneous factors ($1 million net increase).
Electric retail segment purchased power and fuel costs were $328 million
lower in the three-month period ended June 30, 2002, compared to the same period
in the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($54 million);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($58 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power ($207 million);
* decreased costs related to the effects of milder weather on retail
sales ($10 million);
* increased costs related to retail sales growth, excluding weather
effects ($9 million);
* lower purchased power costs related to 2001 generation reliability
program ($6 million); and
* other miscellaneous factors ($2 million net decrease).
Marketing and Trading Segment Gross Margin
Marketing and trading segment revenues were $320 million lower in the
three-month period ended June 30, 2002, compared to the same period in the prior
year. The marketing and trading segment purchased power and fuel costs were $226
million lower in the three-month period ended June 30, 2002, compared to the
same period in the prior year. The lower marketing and trading segment revenues
and purchased power and fuel costs are a result of our transfer of marketing
and trading activities to Pinnacle West in 2001.
The increase in operations and maintenance expense of $2 million was due to
increased overhaul expense and higher employee and other costs partially offset
by lower costs related to generation reliability, plant outages and maintenance
costs.
The decrease in depreciation and amortization expense of $5 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 regulatory settlement, partially offset by increased depreciation on higher
plant balances.
Other income decreased $12 million primarily due to an insurance recovery
recorded in the prior period related to environmental remediation costs.
28
OPERATING RESULTS - SIX-MONTH PERIOD ENDED JUNE 30, 2002 COMPARED WITH SIX-MONTH
PERIOD ENDED JUNE 30, 2001
Our net income for the six months ended June 30, 2002 was $96 million
compared with $131 million for the same period in the prior year. We recognized
a $3 million after-tax loss in the six months ended June 30, 2001 as a
cumulative effect of a change in accounting for derivatives, as required by SFAS
No.133.
Our income before accounting change for the six months ended June 30, 2002
was $96 million compared with $134 million for the same period a year earlier.
The period-to-period decrease was the result of reduced marketing and trading
gross margin due to our transfer of marketing and trading activities to Pinnacle
West in 2001. The reduced marketing and trading gross margin was partially
offset by increased earnings contributions from our regulated retail electricity
operations. The retail comparison was favorably impacted by lower replacement
costs for power plant outages, lower costs for purchased power and gas related
to lower market prices, customer growth and higher average usage per customer,
partially offset by the effects of milder weather and a retail electricity price
decrease.
29
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages $ 108
Lower purchased power and fuel costs related to lower prices,
net of hedge management sales 30
Effects of milder weather on retail sales (22)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 17
Retail price reductions effective July 1, 2001 (13)
Lower purchased power costs related to 2001 generation reliability
program 6
Miscellaneous factors - net 3
-------
Net increase in electric retail segment gross margin 129
Marketing and trading segment gross margin:
Decrease in marketing and trading segment margin resulting
from our transfer of marketing and trading activities to
Pinnacle West in 2001 (195)
-------
Total decrease in the electric retail and the marketing and trading
segments' gross margins (66)
Lower operations and maintenance expense primarily related to lower
costs for generation reliability outages partially offset by higher
other costs 3
Lower depreciation and amortization primarily due to lower regulatory
asset amortization 11
Lower other income (9)
Miscellaneous items, net (2)
-------
Decrease in income before income taxes (63)
Lower income taxes primarily due to lower pretax income 25
-------
Decrease in income before accounting change $ (38)
=======
Electric Retail Segment Gross Margin
Revenues related to our regulated retail and wholesale electricity
businesses were $261 million lower in the six-month period ended June 30, 2002,
compared to the same period in the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($79 million);
* decreased revenues related to retail load hedge management wholesale
sales, as a result of lower sales volumes and lower prices ($166
million);
* decreased retail revenues related to milder weather ($35 million);
30
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($29 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($13 million); and
* other miscellaneous factors ($3 million net increase).
Electric retail segment purchased power and fuel costs were $390 million
lower in the six-month period ended June 30, 2002, compared to the same period
in the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($79 million);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($108 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power ($196 million);
* decreased costs related to the effects of milder weather on retail
sales ($13 million);
* increased costs related to retail sales growth, excluding weather
effects ($12 million); and
* lower purchased power costs related to 2001 generation reliability
program ($6 million).
Marketing and Trading Segment Gross Margin
Marketing and trading segment revenues were $661 million lower in the
six-month period ended June 30, 2002, compared to the same period in the prior
year. Marketing and trading segment purchased power and fuel costs were $466
million lower in the six-month period ended June 30, 2002, compared to the same
period in the prior year. The lower marketing and trading segment revenues and
purchased power and fuel costs are a result of our transfer of marketing and
trading activities to Pinnacle West in 2001.
The decrease in operations and maintenance expense of $3 million was
primarily due to lower costs related to generation reliability, plant outages
and maintenance costs. This decrease was partially offset by increased employee
benefit and other costs.
The decrease in depreciation and amortization expense of $11 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 regulatory settlement, partially offset by increased depreciation on higher
plant balances.
Other income decreased $9 million primarily due to an insurance recovery
recorded in the prior period related to environmental remediation costs
partially offset by net investment gains in the current period.
31
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED JUNE 30, 2002 COMPARED WITH
TWELVE-MONTH PERIOD ENDED JUNE 30, 2001
Our net income for the twelve months ended June 30, 2002 was $230 million
compared with $309 million for the same period in the prior year. We recognized
a $12 million after-tax loss in the twelve months ended June 30, 2002 and a $3
million after-tax loss in the twelve months ended June 30, 2001 as cumulative
effects of a change in accounting for derivatives, as required by SFAS No.133.
Our income before accounting change for the twelve months ended June 30,
2002 was $242 million compared with $312 million for the same period a year
earlier. The period-to-period decrease is the result of our transfer of
marketing and trading activities to Pinnacle West by the end of 2001 and lower
earnings contributions from our marketing and trading activities. The comparison
for marketing and trading activities reflects lower volumes and prices in the
wholesale power markets in the western United States. These negative factors
were partially offset by increased earnings contributions from our regulated
retail electricity operations and lower depreciation and amortization costs. The
retail comparison was favorably impacted by lower replacement costs for power
plant outages, lower costs for purchased power and gas related to lower market
prices, customer growth and higher average usage per customer, partially offset
by higher purchased power costs related to our 2001 generation reliability
program, the effects of milder weather and a retail electricity price decrease.
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
32
Increase
(Decrease)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages $ 126
Higher purchased power and fuel costs related to higher prices,
net of hedge management (8)
Higher retail sales volumes related to customer growth and
higher average usage, excluding weather effects 27
Effects of milder weather on retail sales (9)
Retail price reductions effective July 1, 2001 (28)
Higher purchased power costs related to 2001 generation
reliability program (19)
Miscellaneous factors - net 8
-------
Net increase in electric retail segment gross margin 97
-------
Marketing and trading segment gross margin:
Decrease in marketing and trading segment margin related to our
transfer of marketing and trading activities to Pinnacle
West in 2001 (195)
Decrease in generation sales other than native load due to lower
market prices and resulting lower sales volumes (41)
Increase in other realized marketing and trading in the current
period primarily due to higher volumes 1(a)
Change in prior period mark-to-market gains on contracts
delivered during the current period (b) 23(a)
Lower mark-to-market gains for future period deliveries (b) (4)
-------
Net decrease in marketing and trading gross margin (216)
-------
Total decrease in the electric retail and the marketing and trading
segments' gross margins (119)
Higher operations and maintenance expense primarily related to the
reversal of an environmental reserve in the fourth quarter of
2000 and increased employee benefit and other costs (9)
Lower depreciation and amortization primarily due to lower
regulatory asset amortization 16
Lower other expense primarily related to losses on other
investments in prior periods 6
Lower other income primarily related to insurance recovery in 2001 (9)
Lower net interest expense primarily due to higher capitalized
interest 8
Miscellaneous items, net (6)
-------
Decrease in income before income taxes (113)
Lower income taxes primarily due to lower income 43
-------
Decrease in income before accounting change $ (70)
=======
(a) Net marketing and trading gains (excluding the effects of generation sales
other than native load) recognized for the current period increased $24
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is
economically hedged with a portfolio of forward purchases that protects the
economic value of the sales transactions.
33
Electric Retail Segment Gross Margin
Revenues related to our regulated retail and wholesale electricity
businesses were $463 million lower in the twelve-month period ended June 30,
2002, compared to the same period in the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($177 million);
* decreased revenues related to wholesale sales, as a result of lower
sales volumes and lower prices ($293 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($44 million);
* decreased retail revenues related to milder weather ($14 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($28 million); and
* other miscellaneous factors ($5 million net increase).
Electric retail segment purchased power and fuel costs were $560 million
lower in the twelve-month period ended June 30, 2002, compared to the same
period in the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($177 million);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($126 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power prices ($285 million);
* increased costs related to retail sales growth, excluding weather
effects ($17 million);
* decreased costs related to the effects of milder weather on retail
sales ($5 million);
* higher purchased power costs related to 2001 generation reliability
programs ($19 million); and
* miscellaneous factors ($3 million net decrease).
Marketing and Trading Segment Gross Margin
Marketing and trading segment revenues were $1.29 billion lower in the
twelve-month period ended June 30, 2002, compared to the same period in the
prior year as a result of:
* decreased revenues related to our transfer of marketing and trading
activities to Pinnacle West at the end of 2001 ($661 million);
* decreased revenues from generation sales other than native load due to
lower market prices and resulting lower sales volumes ($84 million);
34
* decreased revenues from other realized marketing and trading in the
current period primarily due to lower prices on higher volumes ($564
million);
* change in prior period mark-to-market gains on contracts delivered
during the current period due to higher volumes being delivered ($25
million increase); and
* lower mark-to-market gains for future period deliveries primarily as a
result of greater market liquidity and greater price volatility,
resulting in higher volumes ($6 million).
Marketing and trading segment purchased power and fuel costs were $1.07
billion lower in the twelve-month period ended June 30, 2002, compared to the
same period in the prior year as a result of:
* decreased purchased power and fuel costs as a result of our transfer
of marketing and trading activities to Pinnacle West at the end of
2001 ($466 million);
* decreased fuel costs related to generation sales other than native
load primarily because of lower sales volumes and lower natural gas
prices ($43 million);
* decreased purchased power costs related to other realized marketing
and trading in the current period primarily due to lower prices on
higher volumes ($565 million);
* change in prior period mark-to-market fuel costs for current period
deliveries related to accounting for derivatives ($2 million
increase); and
* change in mark-to-market fuel costs for future period deliveries ($2
million decrease).
The increase in operations and maintenance expense of $9 million was
primarily related to the reversal of an environmental reserve in the fourth
quarter of 2000 and increased employee benefit and other costs.
The decrease in depreciation and amortization expenses of $16 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 regulatory settlement, partially offset by increased depreciation on higher
plant balances.
Other expense decreased $6 million primarily due to the effects of losses
on other investments in prior periods.
Other income decreased $9 million primarily due to the effects of an
insurance recovery recorded in the prior period related to environmental
remediation costs.
Net interest expense decreased $8 million primarily because of the increase
in capitalized interest and the effects of lower interest rates. These
reductions in net interest expense more than offset the increase in interest
expense on higher debt balances.
35
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the six
months ended June 30, 2002 and estimated capital expenditures for the next three
years (dollars in millions):
Six Months
Ended Estimated
June 30, --------------------------------
2002 2002 2003 2004
-------- -------- -------- --------
Delivery $ 182 $ 347 $ 270 $ 267
Existing generation (a) 70 149 -- --
-------- -------- -------- --------
Total 252 496 270 267
======== ======== ======== ========
(a) Pursuant to the 1999 Settlement Agreement, we are required to transfer our
competitive electric assets and services no later than December 31, 2002.
As we discuss in greater detail in Note 5, on July 23, 2002, an ACC ALJ
issued a recommended order recommending, among other things, that our
ability to transfer our generation assets be stayed until at least July 1,
2004. If the transfer of our generation assets is stayed, we expect our
existing generation capital expenditures to be $116 million in 2003 and $89
million in 2004, resulting in total capital expenditures for those years of
$386 million and $356 million, respectively.
Several years ago, we and the other Palo Verde participants decided to
replace Unit 2 steam generators, which replacement is presently scheduled to be
completed in the fall of 2003. We and the other Palo Verde participants are
currently considering issues related to replacement of the steam generators in
Units 1 and 3. Although a final determination of whether Units 1 and 3 will
require steam generator replacement to operate over their current full licensed
lives has not yet been made, we and the other participants have approved
fabrication of one set of spare steam generators. Our portion of this
expenditure is approximately $27 million, which will be spent from 2002 to 2005.
The capital expenditures table above includes $7 million of these costs in 2002.
If the Palo Verde participants decide to proceed with steam generator
replacement at both Units 1 and 3, we have estimated that our portion of the
fabrication and installation costs and associated power uprate modifications
would be approximately $130 million over the next seven years, which would be
funded with internally-generated cash or external financings. If our generation
assets are not transferred prior to this time, we will make these expenditures.
Existing generation capital expenditures are comprised of multiple
improvements for our existing fossil and nuclear plants. Examples of the types
of projects included in this category are additions, upgrades and capital
replacements of various power plant equipment such as turbines, boilers, and
environmental equipment. The existing generation also contains nuclear fuel
expenditures of approximately $30 million only in 2002. We would make similar
nuclear fuel expenditures in 2003 and 2004 if our nuclear generation assets are
not transferred before those dates. Those expenitures are included in the
additional capital expenditures referenced in Note (a) to the capital
expenditure table.
36
Delivery capital expenditures are comprised of T&D infrastructure additions
and upgrades, capital replacements, new customer construction, and related
information systems and facility costs. Examples of the types of projects
included in the forecast include T&D lines and substations, line extensions to
new residential and commercial developments, and upgrades to customer
information systems. In addition, we began several major transmission projects
in 2001. These projects are periodic in nature and are driven by strong regional
customer growth. We expect to spend about $150 million on major transmission
projects during the 2002-2004 time frame.
CAPITAL RESOURCES AND CASH REQUIREMENTS
The following table summarizes actual cash commitments for the six months
ended June 30, 2002 and estimated commitments for the next five years and
thereafter (dollars in millions):
Six
Months Estimated
Ended -------------------------------------------------------------
June 30, Years Ended December 31,
-------- -------------------------------------------------------------
There-
2002 2002 2003 2004 2005 2006 after
------ ------ ------ ------ ------ ------ ------
Long-term debt payments $ 247 $ 247 $ -- $ 205 $ 400 $ 84 $1,518
Operating leases payments 41 63 61 61 60 60 514
Fuel and purchase power commitments 89 292 128 83 65 68 170
------ ------ ------ ------ ------ ------ ------
Total cash commitments (a) $ 377 $ 602 $ 189 $ 349 $ 525 $ 212 $2,202
====== ====== ====== ====== ====== ====== ======
(a) Total cash commitments are approximately $4.1 billion. The total net
present value of these cash commitments is $2.2 billion.
Our significant debt covenants related to our financing arrangements
include a debt to total capitalization ratio and interest coverage test. We are
in compliance with such convenants and we anticipate that we will continue to
meet all the significant covenant requirement levels. The repercussions of not
meeting the covenants would result in an event of default which, generally
speaking, would require the immediate repayment of the debt subject to the
covenants. All of our bank agreements have cross-default provisions.
Our cash requirements and our ability to fund those requirements are
discussed under "Capital Needs and Resources" in Management's Discussion and
Analysis of Financial Condition and Results of Operation in Part II, Item 7 of
the 2001 10-K.
On March 1, 2002, we issued $375 million of 6.50% Notes due 2012.
On April 15, 2002, we redeemed $122 million of our First Mortgage Bonds,
8.75% Series due 2024. On March 15, 2002, we redeemed at maturity $125 million
of our First Mortgage Bonds, 8.125% Series due 2002. See the cash commitments
table above for our debt repayments. Based on market conditions and optional
call provisions, we may make optional redemptions of long-term debt from time to
time.
37
Although provisions in our first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds and preferred stock that we may issue, we do not expect any
of these provisions to limit our ability to meet its capital requirements.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management
must often make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses, and related disclosures at the date of
the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from
those estimates. Our most critical accounting policies include the determination
of the appropriate accounting for our derivative instruments, mark-to-market
accounting and the impacts of regulatory accounting on our financial statements.
See Note 1 in the 2001 10-K. There have been no material changes since the 2001
10-K.
BUSINESS OUTLOOK
For 2001, our reported income before accounting change was $281 million and
included charges totaling $13 million before income taxes that we do not expect
to recur related to our exposure to Enron and its affiliates. Our earnings have
been negatively affected by the transfer of most of our marketing and trading
activities to Pinnacle West in 2001, as well as retail electricity price
decreases. These negative factors are expected to be significantly offset in
2002 by the absence of significant expenses for reliability and power plant
outages that we incurred in 2001 that we do not expect to recur in 2002 and by
retail customer growth, although the pace of growth is expected to be slower
than in the past. These factors are described in more detail below.
During 2001, in order to meet the highest customer demand in our history,
we incurred significant expenses for our summer reliability program and for
higher replacement power costs related to power plant outages. These efforts,
which cost approximately $140 million before income taxes, are not expected to
be repeated in 2002.
In July 2002, Pinnacle West announced cost-containment measures that
include a voluntary workforce reduction of 500-600 positions. These reductions
would be implemented in the second half of 2002 and are expected to produce
annual operating expense savings at the parent of $30-35 million beginning in
2003, and a comparable one-time charge to its earnings later in 2002.
We estimate our retail customer growth in 2002 to be 3.2%, which is slower
than the pace of growth in recent years, although still about three times the
national average. Our customer growth in 2001 was 3.7%. Our current estimate for
customer growth in 2003 and 2004 is between 3.5% and 4.0% annually.
38
The foregoing discussion of future expectations is forward-looking
information. Actual results may differ materially from expectations. See
"Forward-Looking Statements" below.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See "Business Outlook - Competition and Industry Restructuring" in Item 7
of the 2001 10-K and Note 5 above for a discussion of developments affecting
retail and wholesale electric competition.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona, and from competitive retail and wholesale
bulk power markets in the western United States. These revenues are expected to
be affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer, as well as electricity prices and
variations in weather from period to period.
In our regulated retail market area, we will provide electricity services
to standard-offer, full-service customers and to energy delivery customers who
have chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in our service territory averaged about 4% a year
for the three years 1999 through 2001; we currently expect customer growth to be
about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We
currently estimate that retail electricity sales in kilowatt-hours will grow
3.5% to 5.5% a year in 2002 through 2004, before the retail effects of weather
variations. The customer growth and sales growth referred to in this paragraph
apply to energy delivery customers. As industry restructuring evolves in the
regulated market area, we cannot predict the number of our standard-offer
customers that will switch to unbundled service. As previously noted, under the
1999 Settlement Agreement, we agreed to retail electricity price reductions of
1.5% annually through July 1, 2003 (see Note 5).
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
As we discuss in greater detail in Note 5, on July 23, 2002, an ACC ALJ
issued a recommended order recommending, among other things, that our ability to
transfer our generating assets be stayed until at least July 1, 2004. Pinnacle
West has financed Pinnacle West Energy's generation expansion program premised
upon Pinnacle West Energy's receipt of our generation assets by the end of 2002,
as promised by the 1999 Settlement Agreement. Pinnacle West Energy has
previously received investment grade credit ratings contingent upon its
acquisition of our generation assets. If we are prohibited from transferring our
generation assets to Pinnacle West Energy, Pinnacle West believes that if
Pinnacle West Energy is able to finance its capital requirements (including the
repayment of the bridge financing provided by Pinnacle West), it would only be
able to do so on commercially unattractive terms. In such a case, Pinnacle
West's overall financing costs could increase. As we discuss in Note 5, we have
proposed that we be permitted to acquire certain of Pinnacle West Energy's
generating facilities if the ACC prohibits or delays our transfer of generation
assets to Pinnacle West Energy. If we were to acquire Pinnacle West Energy
generation assets, we believe that we could obtain financing for those assets
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and could do so on terms more favorable than those that would be otherwise
available to Pinnacle West Energy.
Purchased power and fuel costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, new generating plants being placed
in service and our hedging program for managing such costs.
Operations and maintenance expenses are expected to be affected by sales
mix and volumes, power plant operations, inflation, outages and other factors.
See "Business Outlook" above for information regarding Pinnacle West
cost-containment measures announced in July 2002.
Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property, and changes in
regulatory asset amortization.
Taxes other than income taxes consist primarily of property taxes, which
are affected by tax rates and the value of property in service and under
construction. The average property tax rate for us was 9.32% of assessed value
for 2001 and 9.16% for 2000. We expect property taxes to increase primarily due
to our additions to existing facilities.
Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factor affecting borrowing levels in
the next several years is expected to be our internally-generated cash flow.
Capitalized interest offsets a portion of interest expense while capital
projects are under construction. We stop recording capitalized interest on a
project when it is placed in commercial operation.
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete
effectively in a restructured industry.
Our financial results may be affected by the application of SFAS No. 133.
See Note 10 for further information.
Our financial results may be affected by a number of broad factors. See
"Forward-Looking Statements" below for further information on such factors,
which may cause our actual future results to differ from those we currently seek
or anticipate.
RATE MATTERS
See Note 5 for a discussion of a price reduction effective as of July 1,
2002, and for a discussion of the 1999 Settlement Agreement that will, among
other things, result in five annual price reductions over a four-year period
ending July 1, 2003.
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FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements, except as
required by applicable laws. Because actual results may differ materially from
expectations, we caution readers not to place undue reliance on these
statements. A number of factors could cause future results to differ materially
from historical results, or from results or outcomes currently expected or
sought by us. These factors include the ongoing restructuring of the electric
industry, including the introduction of retail electric competition in Arizona;
the outcome of regulatory and legislative proceedings relating to the
restructuring; state and federal regulatory and legislative decisions and
actions, including the price mitigation plan adopted by the FERC; regional
economic and market conditions, including the California energy situation and
completion of generation construction in the region, which could affect customer
growth and the cost of power supplies; the cost of debt and equity capital;
weather variations affecting local and regional customer energy usage;
conservation programs; power plant performance; regulatory issues associated
with generation expansion, such as permitting and licensing; our ability to
compete successfully outside traditional regulated markets (including the
wholesale market); and technological developments in the electric industry.
These factors and the other matters discussed above may cause future
results to differ materially from historical results, or from results or
outcomes we currently expect or seek.
ITEM 3. MARKET RISKS
Our operations include managing market risks related to changes in interest
rates, commodity prices, and investments held by our nuclear decommissioning
trust fund.
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage risks associated with
these market fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.
In 2001, subject to specified risk parameters established by Pinnacle
West's Board of Directors and monitored by Pinnacle West's Energy Risk
Management Committee, we engaged in trading activities intended to profit from
market price movements. In accordance with EITF 98-10, "Accounting For Contracts
Involved in Energy Trading and Risk Management Activities," such trading
positions are marked-to-market. These trading activities are part of our
marketing and trading activities and are reflected in the marketing and trading
segment revenues and expenses.
As of June 30, 2002, a hypothetical adverse price movement of 10% in the
market price of our risk management and trading assets and liabilities would
have decreased the fair market value of these contracts by approximately $16
million. A hypothetical favorable price movement of 10% would have increased the
fair market value of these contracts by approximately $18 million.
41
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We use a risk management process to assess and monitor the
financial exposure of this and all other counterparties. Despite the fact that
the great majority of trading counterparties are rated as investment grade by
the credit rating agencies, there is still a possibility that one or more of
these companies could default, resulting in a material impact on earnings for a
given period. Counterparties in the portfolio consist principally of major
energy companies, municipalities, and local distribution companies. We maintain
credit policies that we believe minimize overall credit risk to within
acceptable limits. Determination of the credit quality of our counterparties is
based upon a number of factors, including credit ratings and our evaluation of
their financial condition. In many contracts, we employ collateral requirements
and standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Valuation adjustments are
established representing our estimated credit losses on our overall exposure to
counterparties.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our nuclear decommissioning trust fund. Our policy is to
manage interest rates through the use of a combination of fixed-rate and
floating-rate debt. The nuclear decommissioning fund also has risks associated
with changing market values of equity investments. Nuclear decommissioning costs
are recovered in regulated electricity prices.
42
PART II - OTHER INFORMATION
ITEM 5. OTHER INFORMATION
CONSTRUCTION AND FINANCING PROGRAMS
See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
a discussion of construction and financing programs of the Company.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of
this report for a discussion of regulatory developments regarding the
introduction of retail electric competition in Arizona and related matters.
PALO VERDE NUCLEAR GENERATING STATION
In February 2002, the U. S. Secretary of Energy recommended to President
Bush that the Yucca Mountain, Nevada site be developed as a permanent repository
for spent nuclear fuel. The President transmitted this recommendation to
Congress and the State of Nevada vetoed the President's recommendation. See
"Palo Verde Nuclear Generating Station" in Part II, Item 5 of the March 10-Q.
Congress recently approved the Yucca Mountain site, overriding the Nevada veto.
It is now expected that the U.S. Department of Energy will submit a license
application to the NRC late in 2004.
NATURAL GAS SUPPLY
In a pending FERC proceeding, EL Paso Natural Gas Company has proposed
allocating its gas pipeline capacity in such a way that our (and other companies
with the same contract type) gas transportation rights could be significantly
impacted, and various parties, including us and Pinnacle West Energy, have
challenged this allocation. See "Generating Fuel and Purchased Power - Natural
Gas Supply" in Part I, Item 1 of the 2001 10-K. The FERC conducted a public
conference in April 2002 to discuss an appropriate mechanism for allocating
capacity on the El Paso Natural Gas Company pipeline. On May 31, 2002 the FERC
issued an order requiring the conversion of all firm, Full Requirements
contracts to Contract Demand contracts by November 1, 2002. In addition, the
FERC order set forth procedures to encourage parties to resolve the details of
such conversions through the settlement process. We and other Full Requirement
contract holders have sought rehearing of the FERC order and have requested a
stay of the November 1, 2002 implementation date. We cannot currently predict
the outcome of this matter.
COAL SUPPLY
Because covenants under the Four Corners lease and related federal
rights-of-way and grants expired in July 2001, the Navajo Nation assessed taxes
on the coal supplier and the plant. See "Generating Fuel and Purchased Power -
Coal Supply - Four Corners" in Part I, Item 1 of the 2001 10-K. In July 2002, we
negotiated a settlement agreement with the Navajo Nation relating to the plant
pursuant to which we will make settlement payments to the Navajo Nation. That
settlement agreement is expected to be executed in August 2002. Pursuant to the
terms of the settlement agreement, we do not expect the payments to have a
material adverse impact on our financial position, results of operations or
liquidity.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
12.1 Ratio of Earnings to Fixed Charges
In addition, the Company hereby incorporates the following Exhibits
pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to
the filings set forth below:
Originally Filed Date
Exhibit No. Description as Exhibit: File No.(a) Effective
- ----------- ----------- -------------------- ----------- ---------
3.1 Articles of Incorporation 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, Registration Nos.
1988 33910 and 33--55248
by means of September
24, 1993 Form 8-K
Report
3.2 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 1-20-00
February 20, 1996 Report
10.1 Amendment to Letter 10.1 to Pinnacle West 1-8962 8-13-02
Agreement effective as of June 2002 Form 10-Q
January 1, 2002 between Report
the Company and William
L. Stewart
10.2 Summary of James M. 10.2 to Pinnacle West 1-8962 8-13-02
Levine Retirement June 2002 Form 10-Q
Benefits Report
- ----------
(a) Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
44
(b) Reports on Form 8-K
During the quarter ended June 30, 2002, and the period from July 1 through
August 13, 2002, we filed the following reports on Form 8-K:
Report dated April 19, 2002 regarding a motion filed by APS in a
consolidated ACC docket.
Report dated April 26, 2002 regarding procedural orders issued by the ACC
in a consolidated ACC docket.
Report dated May 22, 2002 regarding responses to FERC data requests that
were filed with the FERC on May 22, 2002.
Report dated June 5, 2002 regarding responses to FERC data requests that
were filed with the FERC on June 5, 2002.
Report dated July 11, 2002 regarding a letter filed by APS with the ACC
discussing the circumstances under which APS would support a temporary
suspension or stay of certain Arizona electric competition rules.
Report dated July 23, 2002 regarding ALJ recommendations in a consolidated
ACC docket.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Company has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Dated: August 13, 2002 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Financial Officer
and Officer Duly Authorized
to sign this Report)
46