FORM 10-Q
Securities and Exchange Commission
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 2001
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 N. Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999
(Address of principal executive offices) (Zip Code)
(602) 250-1000
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
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 14, 2001: 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
APS Energy Services - APS Energy Services Company, Inc., a Pinnacle West
subsidiary
CC&N - Certificate of Convenience and Necessity
Citizens - Citizens Communications Company
Company - Arizona Public Service Company
EITF - Emerging Issues Task Force
El Paso - El Paso Natural Gas Company
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
ISO - California Independent System Operator
ITC - investment tax credit
KW - kilowatt, one thousand watts
KWh - kilowatt-hour, one thousand watts per hour
March 2001 10-Q - Arizona Public Service Company Quarterly Report on Form 10-Q
for the fiscal quarter ended March 31, 2001
MW - megawatt, one million watts
MWh - megawatt-hour, one million watts per hour
1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition
Palo Verde - Palo Verde Nuclear Generating Station
PG&E - PG&E Corp.
Pinnacle West - Pinnacle West Capital Corporation
Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West
subsidiary
PX - California Power Exchange
Rules - ACC retail electric competition rules
Salt River Project - Salt River Project Agricultural Improvement and Power
District
SCE - Southern California Edison
SFAS- Statement of Financial Accounting Standards
2000 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 2000
-2-
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended June 30,
----------------------------
2001 2000
--------- ---------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES ................................................ $ 840,660 $ 719,394
--------- ---------
PURCHASED POWER AND FUEL COSTS:
Purchased power .......................................................... 329,161 215,095
Fuel for electric generation ............................................. 122,278 73,267
--------- ---------
Total ................................................................. 451,439 288,362
--------- ---------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS ..................... 389,221 431,032
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs ...... 121,052 104,432
Depreciation and amortization ............................................ 104,643 107,428
Income taxes ............................................................. 42,840 62,542
Other taxes .............................................................. 25,448 25,596
--------- ---------
Total ................................................................. 293,983 299,998
--------- ---------
OPERATING INCOME ........................................................... 95,238 131,034
--------- ---------
OTHER INCOME (DEDUCTIONS):
Income taxes ............................................................. (3,005) 823
Other - net .............................................................. 6,971 (1,995)
--------- ---------
Total ................................................................. 3,966 (1,172)
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS .......................................... 99,204 129,862
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ............................................... 31,239 32,607
Interest on short-term borrowings ........................................ 1,515 3,853
Debt discount, premium and expense ....................................... 1,006 231
Capitalized interest ..................................................... (4,195) (2,680)
--------- ---------
Total ................................................................. 29,565 34,011
--------- ---------
EARNINGS FOR COMMON STOCK .................................................. $ 69,639 $ 95,851
========= =========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Six Months
Ended June 30,
--------------------------------
2001 2000
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES ............................................... $ 1,521,931 $ 1,165,375
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Purchased power ......................................................... 505,118 282,048
Fuel for electric generation ............................................ 243,457 131,512
----------- -----------
Total .............................................................. 748,575 413,560
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .................... 773,356 751,815
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs...... 235,593 212,809
Depreciation and amortization ........................................... 208,339 208,794
Income taxes ............................................................ 86,408 83,352
Other taxes ............................................................. 50,744 50,977
----------- -----------
Total .............................................................. 581,084 555,932
----------- -----------
OPERATING INCOME .......................................................... 192,272 195,883
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ............................................................ (1,785) 169
Other - net ............................................................. 3,565 (422)
----------- -----------
Total .............................................................. 1,780 (253)
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ......................................... 194,052 195,630
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt .............................................. 63,820 65,945
Interest on short-term borrowings ....................................... 2,476 5,120
Debt discount, premium and expense ...................................... 1,335 845
Capitalized interest .................................................... (7,824) (4,906)
----------- -----------
Total .............................................................. 59,807 67,004
----------- -----------
INCOME FROM CONTINUING OPERATIONS ......................................... 134,245 128,626
Cumulative Effect of a Change in Accounting for Derivatives -
net of income taxes of $1,793 ......................................... (2,755) --
----------- -----------
EARNINGS FOR COMMON STOCK ................................................. $ 131,490 $ 128,626
=========== ===========
See Notes to Condensed Financial Statements
-4-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended June 30,
-------------------------------
2001 2000
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES ............................................... $ 3,836,808 $ 2,532,755
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Purchased power ......................................................... 1,770,534 708,991
Fuel for electric generation ............................................ 443,219 263,862
----------- -----------
Total .............................................................. 2,213,753 972,853
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .................... 1,623,055 1,559,902
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs ..... 452,876 443,552
Depreciation and amortization ........................................... 425,024 419,208
Income taxes ............................................................ 203,033 183,602
Other taxes ............................................................. 99,497 96,714
----------- -----------
Total .............................................................. 1,180,430 1,143,076
----------- -----------
OPERATING INCOME .......................................................... 442,625 416,826
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ............................................................ 2,358 21,258
Other - net ............................................................. (6,870) (7,650)
----------- -----------
Total .............................................................. (4,512) 13,608
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ......................................... 438,113 430,434
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt .............................................. 132,306 131,197
Interest on short-term borrowings ....................................... 4,811 9,388
Debt discount, premium and expense ...................................... 2,595 1,824
Capitalized interest .................................................... (13,812) (5,586)
----------- -----------
Total .............................................................. 125,900 136,823
----------- -----------
INCOME FROM CONTINUING OPERATIONS ......................................... 312,213 293,611
Extraordinary charge - net of income taxes of $94,115 ................... -- (139,885)
Cumulative Effect of a Change in Accounting for Derivatives -
net of income taxes of $1,793 ......................................... (2,755) --
----------- -----------
EARNINGS FOR COMMON STOCK ................................................. $ 309,458 $ 153,726
=========== ===========
See Notes to Condensed Financial Statements
-5-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Unaudited)
June 30, December 31,
2001 2000
----------- -----------
(Dollars in Thousands)
UTILITY PLANT:
Electric plant in service and held for future use .......... $ 7,971,037 $ 7,805,025
Less accumulated depreciation and amortization ............. 3,276,353 3,187,328
----------- -----------
Total ............................................... 4,694,684 4,617,697
Construction work in progress .............................. 264,314 245,749
Nuclear fuel, net of amortization .......................... 48,062 47,389
----------- -----------
Utility plant - net ................................. 5,007,060 4,910,835
----------- -----------
INVESTMENTS AND OTHER ASSETS ............................... 350,647 269,678
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents .................................. 9,980 2,609
Trust fund for bond redemption ............................. 72,370 --
Accounts receivable:
Service customers ........................................ 239,352 422,012
Other .................................................... 58,724 48,711
Allowance for doubtful accounts .......................... (2,430) (2,380)
Accrued utility revenues ................................... 105,334 74,566
Materials and supplies, at average cost .................... 80,060 71,966
Fossil fuel, at average cost ............................... 25,401 19,405
Deferred income taxes ...................................... 5,793 5,793
Assets from risk management and trading activities ......... 137,938 17,506
Other ...................................................... 39,626 38,414
----------- -----------
Total current assets ................................ 772,148 698,602
----------- -----------
DEFERRED DEBITS:
Regulatory assets .......................................... 403,840 469,867
Unamortized debt issue costs ............................... 12,031 12,805
Other ...................................................... 50,688 37,928
----------- -----------
Total deferred debits ............................... 466,559 520,600
----------- -----------
TOTAL ............................................... $ 6,596,414 $ 6,399,715
=========== ===========
See Notes to Condensed Financial Statements.
-6-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES
(Unaudited)
June 30, December 31,
2001 2000
----------- -----------
(Dollars in Thousands)
CAPITALIZATION:
Common stock .............................................. $ 178,162 $ 178,162
Additional paid-in capital ................................ 1,246,804 1,246,804
Retained earnings ......................................... 741,291 694,802
Accumulated Other Comprehensive Loss ...................... (51,912) --
----------- -----------
Common stock equity ................................ 2,114,345 2,119,768
Long-term debt less current maturities .................... 1,623,947 1,806,908
----------- -----------
Total capitalization ............................... 3,738,292 3,926,676
----------- -----------
CURRENT LIABILITIES:
Commercial paper .......................................... 162,000 82,100
Current maturities of long-term debt ...................... 375,266 250,266
Accounts payable .......................................... 168,022 267,999
Accrued taxes ............................................. 196,898 106,515
Accrued interest .......................................... 33,923 39,488
Customer deposits ......................................... 26,178 24,498
Liabilities from risk management and trading activities ... 178,210 37,179
Other ..................................................... 64,178 104,947
----------- -----------
Total current liabilities .......................... 1,204,675 912,992
----------- -----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ..................................... 1,047,514 1,110,437
Unamortized gain - sale of utility plant .................. 66,348 68,636
Customer advances for construction ........................ 70,926 40,694
Other ..................................................... 468,659 340,280
----------- -----------
Total deferred credits and other ................... 1,653,447 1,560,047
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 6, 7, and 9)
TOTAL .............................................. $ 6,596,414 $ 6,399,715
=========== ===========
See Notes to Condensed Financial Statements.
-7-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months
Ended June 30,
----------------------------
2001 2000
--------- ---------
(Dollars in Thousands)
Cash Flows from Operating Activities:
INCOME FROM CONTINUING OPERATIONS ..................... $ 134,245 $ 128,626
Items not requiring cash:
Depreciation and amortization ....................... 208,339 208,794
Nuclear fuel amortization ........................... 14,178 15,124
Deferred income taxes - net ......................... (27,350) (34,932)
Changes in certain current assets and liabilities:
Accounts receivable - net ........................... 172,697 (127,978)
Accrued utility revenues ............................ (30,768) (39,342)
Materials, supplies and fossil fuel ................. (14,090) 81
Other current assets ................................ (1,212) (9,211)
Accounts payable .................................... (103,888) 56,919
Accrued taxes ....................................... 90,383 126,694
Accrued interest .................................... (5,565) (938)
Other current liabilities ........................... (39,089) 8,181
Risk management and trading activities - net ........ (62,419) --
Other - net ........................................... 36,170 (11,977)
--------- ---------
Net cash flow provided by operating activities.... 371,631 320,041
--------- ---------
Cash Flows from Investing Activities:
Trust fund for bond redemption ........................ (72,370) --
Capital expenditures .................................. (222,548) (189,401)
Capitalized interest .................................. (7,824) (4,906)
Other ................................................. 1,855 (3,114)
--------- ---------
Net cash flow used for investing activities ...... (300,887) (197,421)
--------- ---------
Cash Flows from Financing Activities:
Short-term borrowings - net ........................... 79,900 162,575
Dividends paid on common stock ........................ (85,000) (42,500)
Repayment and reacquisition of long-term debt ......... (58,273) (242,000)
--------- ---------
Net cash flow used for financing activities ...... (63,373) (121,925)
--------- ---------
Net increase in cash and cash equivalents ............... 7,371 695
Cash and cash equivalents at beginning of period ........ 2,609 7,477
--------- ---------
Cash and cash equivalents at end of period .............. $ 9,980 $ 8,172
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........... $ 63,932 $ 64,470
Income taxes ........................................ $ 25,760 $ 1,544
See Notes to Condensed Financial Statements.
-8-
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 Notes 9 and 10)and the extraordinary charge
(see Note 5). 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 2000 10-K. We have reclassified
certain prior year amounts to conform to the current year presentation.
2. Weather conditions and trading and wholesale power marketing activities can
have significant impacts on our results for interim periods. 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. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
changes in capitalization for the six months ended June 30, 2001.
5. Regulatory Accounting
We are regulated by the ACC and the FERC. The accompanying financial
statements reflect the ratemaking policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements.
During 1997, the EITF of the FASB issued EITF 97-4. EITF 97-4 requires that
SFAS No. 71 be discontinued no later than when legislation is passed or a rate
order is issued that contains sufficient detail to determine its effect on the
portion of the business being deregulated, which could result in write-downs or
write-offs of physical and/or regulatory assets. Additionally, the EITF
determined that regulatory assets should not be written off if they are to be
recovered from a portion of the entity which continues to apply SFAS No. 71.
The 1999 Settlement Agreement was approved by the ACC in September 1999
(see Note 6 for a discussion of the agreement). Consequently, we have
discontinued the application of SFAS No. 71 for our generation operations. As a
result, we tested the generation assets for impairment and determined that the
generation assets were not impaired. Pursuant to the 1999 Settlement Agreement,
a regulatory disallowance removed $234 million pretax ($183 million net present
value) from ongoing regulatory cash flows and was recorded as a net reduction of
regulatory assets. This reduction ($140 million after income taxes) was reported
as an extraordinary charge on the income statement during the third quarter of
1999. Prior to the 1999 Settlement Agreement, under the 1996 regulatory
agreement (see Note 6), the ACC accelerated the amortization of substantially
all of our regulatory assets to an eight-year period that would have ended June
30, 2004.
-9-
The regulatory assets to be recovered under the 1999 Settlement Agreement
are now being amortized through June 30, 2004 as follows (dollars in millions):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
The majority of our remaining regulatory assets relate to deferred income
taxes and rate synchronization cost deferrals.
The condensed balance sheets include the amounts listed below for
generation assets not subject to SFAS No. 71 (for additional generation
information see Note 8):
(dollars in thousands)
June 30, December 31,
2001 2000
----------- -----------
Electric plant in service and held for future use.. $ 3,873,707 $ 3,856,600
Accumulated depreciation and amortization ......... (1,745,172) (1,693,079)
Construction work in progress ..................... 101,980 86,329
Nuclear fuel, net of amortization ................. 48,062 47,389
6. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
1999 SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive
Settlement Agreement with various parties, including representatives of major
consumer groups, related to the implementation of retail electric competition.
On September 23, 1999, the ACC voted to approve the 1999 Settlement Agreement,
with some modifications. On December 13, 1999, two parties filed lawsuits
challenging the ACC's approval of the 1999 Settlement Agreement. Each party
bringing the lawsuits appealed the ACC's order approving the 1999 Settlement
Agreement directly to the Arizona Court of Appeals, as provided by Arizona law.
In one of the appeals, on December 26, 2000, the Arizona Court of Appeals
affirmed the ACC's approval of the 1999 Settlement Agreement. This decision was
not appealed and has become final. In the other appeal, on April 5, 2001, the
Arizona Court of Appeals again affirmed the ACC's approval of the 1999
Settlement Agreement. The Arizona Consumers Council, which filed that appeal,
has petitioned the Arizona Supreme Court for review of the Court of Appeals'
decision.
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
-10-
reduction of approximately $24 million ($14 million after income taxes)
included the July 1, 1999 retail price decrease of approximately $11
million ($7 million after income taxes) related to the 1996 regulatory
agreement. See "1996 Regulatory Agreement" below. Based on the price
reduction authorized in the 1999 Settlement Agreement, there were retail
price decreases of approximately $28 million ($17 million after taxes), or
1.5%, effective July 1, 2000, and approximately $27 million ($16 million
after taxes), or 1.5%, effective July 1, 2001. For customers having loads
three MW or greater, standard offer rates will be 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 the Company 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, or material changes in our cost
of service for ACC-regulated services resulting from federal, tribal, state
or local laws, regulatory requirements, judicial decisions, actions or
orders.
* We will be permitted to defer for later recovery prudent and reasonable
costs of complying with the ACC electric competition 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 electric competition 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 the 1996
regulatory agreement. In addition, the 1999 Settlement Agreement states
that we have demonstrated that our 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
-11-
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 generating assets and
competitive services at book value as of the date of transfer, and will
complete the transfer no later than December 31, 2002. Accordingly, we plan
to complete the move of such assets and services to the parent company or
to Pinnacle West Energy by the end of 2002, as required. 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.
* When the 1999 Settlement Agreement approved by the ACC is no longer subject
to judicial review, we will move to dismiss all of our litigation pending
against the ACC as of the date we entered into the 1999 Settlement
Agreement. To protect our rights, we have several lawsuits pending on ACC
orders relating to stranded cost recovery and the adoption and amendment of
the ACC's electric competition rules, which would be voluntarily dismissed
at the appropriate time under this provision.
As discussed in Note 5 above, we have discontinued the application of SFAS
No. 71 for our generation operations.
Although the Rules allow retail customers to have access to competitive
providers of energy and energy services (see "Retail Electric Competition Rules"
below), we are the "provider of last resort" for standard offer customers under
rates that have been approved by the ACC. Energy prices in the western wholesale
market vary and, during the course of the last year, have been volatile. At
various times, prices in the spot wholesale market have significantly exceeded
the amount included in our current retail rates. We expect similar market
conditions to continue through 2001 and 2002. We believe that through a
combination of hedging and our current generation portfolio, we will be able to
adequately manage our exposure to the volatility of the power market. However,
in the event of shortfalls due to unforeseen increases in load demand or
generation 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.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve rules that provide a framework for the introduction of retail electric
competition in Arizona. 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 December 8,
1999, we filed a lawsuit to protect our legal rights regarding the Rules. This
lawsuit is pending, along with several other lawsuits on ACC orders relating to
stranded cost recovery (including those described above involving us), the
adoption or amendment of the Rules, and the certification of competitive
electric service providers.
-12-
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,
including APS Energy Services, 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 case has been appealed to the Arizona Supreme Court, where a decision is
pending.
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
non-competitive 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
generation assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the 1999 Settlement Agreement, we
received a waiver to allow transfer of our generation and other
competitive assets and services to affiliates no later than December
31, 2002. We plan to complete the move of such assets by the end of
2002, as required.
1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and us. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (dollars in millions):
-13-
Annual Electric Percentage
Revenue Decrease Decrease Effective Date
---------------- -------- --------------
$49 3.4% July 1, 1996
$18 1.2% July 1, 1997
$17 1.1% July 1, 1998
$11 0.7% July 1, 1999 (a)
(a) Included in the first rate reduction under the 1999 Settlement Agreement
(see above).
The regulatory agreement also required the parent to infuse $200 million of
common equity into us in annual payments of $50 million from 1996 through 1999.
All of these equity infusions were made by December 31, 1999.
LEGISLATION. In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:
* Arizona's largest government-operated electric utility (Salt River
Project) and, at their option, smaller municipal electric systems must
(i) make at least 20% of their 1995 retail peak demand available to
electric service providers by December 31, 1998 and for all retail
customers by December 31, 2000; (ii) decrease rates by at least 10%
over a ten-year period beginning as early as January 1, 1991; (iii)
implement procedures and public processes comparable to those already
applicable to public service corporations for establishing the terms,
conditions, and pricing of electric services as well as certain other
decisions affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt
River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive
basis during the first two years of competition only for customers
having demands in excess of one MW (and that are eligible for
competitive generation services), and thereafter for all customers
receiving competitive electric generation.
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.
FEDERAL
The 1992 Energy Act and recent rulemakings by FERC have promoted increased
competition in the wholesale energy markets. We do not expect these rules to
have a material impact on our financial statements.
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Several electric utility industry restructuring bills will undoubtedly be
introduced during the current congressional session. Several bills have been
written to allow consumers to choose their electricity suppliers beginning in
2001 and beyond. These bills and other bills that are expected to be introduced,
and ongoing discussions at the federal level suggest a wide range of opinion
that will need to be narrowed before any comprehensive restructuring of the
electric utility industry can occur.
In June 2001 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 remains in effect until September 30, 2002. The Company cannot
accurately predict the overall financial impact of the plan on the various
aspects of its business, including its wholesale and purchased power activities.
7. Nuclear Insurance
The Palo Verde participants have insurance for public liability payments
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
29.1% interest in the three Palo Verde units, our maximum potential assessment
per incident 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 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.
8. Business Segments
We have two principal business segments (determined by products, services
and regulatory environment), which consist of the transmission and distribution
of electricity activities (delivery business segment) and the generation of
electricity and wholesale activities (generation business segment).
These reportable segments reflect a change in the reporting of our
functional activities. Before January 1, 2001, our reported segment information
combined transmission and distribution of electricity activities with wholesale
activities. Our current operational activities are more closely based on the
strong integration of our wholesale activities and our generation of electricity
activities, and have been combined for segment reporting purposes. The
corresponding information for earlier periods has been restated.
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The periods ended September 30, 2000 and December 31, 2000 have not yet
been reported on a restated basis. When earnings are restated, the following
amounts for the periods ended September 30, 2000 will be moved to the generation
business segment from the delivery business segment: $29 million for the three
months; $53 million for the nine months; and $54 million for the twelve months.
The restatement for the twelve month period ended December 31, 2000 will result
in $62 million in earnings being moved to the generation business segment from
the delivery business segment.
Beginning in 2001, we changed our method of allocating revenues between the
delivery business segment and the generation business segment to reflect the
seasonal impact of market prices. This change had the impact of increasing
delivery segment income and decreasing generation segment income in all the
periods presented when compared to the prior comparable periods. The after-tax
change is $35 million in the three-month ended period and $43 million in the six
and twelve-month ended periods.
Eliminations primarily relate to intersegment sales of electricity. Segment
information for the three, six and twelve months ended June 30, 2001 and 2000 is
as follows (dollars in millions):
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
------------------ ------------------ ------------------
2001 2000 2001 2000 2001 2000
------- ------- ------- ------- ------- -------
Operating Revenues:
Delivery $ 557 $ 508 $ 965 $ 880 $ 2,055 $ 1,875
Generation 521 446 977 692 2,694 1,510
Eliminations (237) (235) (420) (407) (912) (852)
------- ------- ------- ------- ------- -------
Total $ 841 $ 719 $ 1,522 $ 1,165 $ 3,837 $ 2,533
======= ======= ======= ======= ======= =======
Income from Continuing Operations:
Delivery $ 65 $ 32 $ 89 $ 56 $ 138 $ 145
Generation 5 64 45 73 174 149
------- ------- ------- ------- ------- -------
Total $ 70 $ 96 $ 134 $ 129 $ 312 $ 294
======= ======= ======= ======= ======= =======
As of June 30, As of December 31,
2001 2000
---- ----
Assets:
Delivery $3,934 $3,987
Generation 2,662 2,413
------ ------
Total $6,596 $6,400
====== ======
9. Accounting Matters
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 sheet and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholder's equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge
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accounting criteria. Hedge effectiveness is measured based on the relative
changes in fair value between the derivative contract and the hedged item over
time. Any change in the fair value resulting from ineffectiveness is recognized
immediately in net income. This new standard may result in additional volatility
in our net income and comprehensive income.
In June 2001, the FASB determined that electricity contracts, including
those with option characteristics and those subject to "bookout," would qualify
for the normal purchases and sales exception if certain criteria were met. Prior
to the issuance of the guidance, we accounted for electricity contracts with
characteristics of options and those subject to "bookout" as normal purchases
and sales. As a result, we did not mark these contracts to their fair market
values each reporting period. The effective date of this new guidance is July 1,
2001.
We estimate the impacts of the new guidance are a $12 million after-tax
loss in earnings and an $8 million after-tax gain in equity (as a component of
other comprehensive income). These adjustments resulted from option contracts
that did not meet the new criteria for the normal purchases and sales exception.
The impact of the new guidance will be reflected as a cumulative effect of a
change in accounting principle in the third quarter of 2001. See Note 10 for
discussion on the impact of SFAS No. 133.
In July 2001, the FASB issued 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 are currently evaluating the new standard and do not
expect it to have a material impact on our financial statements.
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/credits. The changes in market value of such contracts have a high
correlation to price changes in the hedged commodity. In addition, subject to
specified risk parameters we engage in trading activities intended to profit
from market price movements.
As a result of adopting SFAS No. 133, we recognized $118 million of
derivative assets and $16 million of derivative liabilities in our balance sheet
as of January 1, 2001. Also as of January 1, 2001, we recorded a $3 million
after-tax loss in net income as a cumulative effect of a change in accounting
principle and a $65 million after-tax gain in equity (as a component of other
comprehensive income). The gain resulted from unrealized gains on cash flow
hedges. See Note 9 for discussion on SFAS No. 133.
-17-
The change in derivative fair value in the consolidated statements of
income for the three, six and twelve months ending June 30, 2001 and 2000 is
comprised of the following (dollars in thousands):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
------------------ ------------------ -------------------
2001 2000 2001 2000 2001 2000
------- ------- ------- ------- ------- --------
Ineffective portion of derivatives
qualifying for hedge accounting (a) $(1,941) $ -- $ (312) $ -- $ (312) $ --
Discontinuance of cash flow hedges
for forecasted transactions that
will not occur (7,718) -- (7,718) -- (7,718) --
------- ------- ------- ------- ------- --------
TOTAL $(9,659) $ -- $(8,030) $ -- $(8,030) $ --
======= ======= ======= ======= ======= ========
(a) Time value component of options excluded from assessment of hedge
effectiveness.
As of June 30, 2001, the maximum length of time over which we are hedging
our exposure to the variability in future cash flows for forecasted transactions
is forty-two months. During the twelve months ending June 30, 2002, we estimate
that a net loss of $7 million before income taxes will be reclassified from
accumulated other comprehensive income as an offset to the effect on earnings of
market price changes for the related hedged transaction.
Net gains and losses on derivatives utilized for trading activities are
recognized in power marketing revenues on a current basis (the mark to market
method). Trading positions are measured at fair value as of the balance sheet
date. The net gains recognized in power marketing revenues were the following
for the three, six and twelve months ended June 30, 2001 and 2000 (dollars in
millions):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
------------ ------------ -----------
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Mark to market gains $ 42 $ 22 $ 95 $ 27 $ 76 $ 28
Realized gains/(losses) (9) 14 (1) 14 35 19
---- ---- ---- ---- ---- ----
Total trading gains $ 33 $ 36 $ 94 $ 41 $111 $ 47
==== ==== ==== ==== ==== ====
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11. Comprehensive Income
Components of comprehensive income for the three-month, six-month and
twelve-month periods ended June 30, 2001 and 2000, are as follows (dollars in
thousands):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
-------------------- --------------------- --------------------
2001 2000 2001 2000 2001 2000
--------- --------- --------- --------- --------- ---------
Net Income $ 69,639 $95,851 $131,490 $128,626 $309,458 $153,726
-------- ------- -------- -------- -------- --------
Other comprehensive income/(loss), net of tax:
Cumulative effect of change in accounting
for derivatives -- -- 64,700 -- 64,700 --
Unrealized holding losses arising during period (87,475) -- (97,928) -- (97,928) --
Reclassification adjustment for derivatives (1,862) -- (18,684) -- (18,684) --
-------- ------- -------- -------- -------- --------
Total other comprehensive loss (89,337) -- (51,912) -- (51,912) --
-------- ------- -------- -------- -------- --------
Comprehensive Income/(Loss) $(19,698) $95,851 $ 79,578 $128,626 $257,546 $153,726
======== ======= ======== ======== ======== ========
12. California Energy Market Issues and Refunds in the Pacific Northwest
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 power marketing exposures. Based on the financial transactions to
date, we do not believe the foregoing matters will have a material adverse
effect on our financial position or 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.
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 FERC
after the California ISO provides necessary historical data. FERC also ordered
an evidentiary proceeding to discuss and evaluate possible refunds for the
Pacific Northwest. Although FERC has not yet calculated the refund amounts, we
do not expect that the resolution of this issue will have a material adverse
impact on the Company's financial position, results of operations or liquidity.
13. Power Service Agreement
By letter dated March 7, 2001, Citizens Communications Company 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. The Company and Citizens terminated
the power service
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agreement, effective July 15, 2001. In replacement of the power service
agreement, the parent company and Citizens entered into a power sale agreement
under which the parent company 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.
14. 2001 Generation Summer Reliability Program
We recently added over 200 MW of generating capability to enhance
reliability for the summer of 2001 in light of market conditions in the western
United States. We restored approximately 100 MW of previously mothballed
gas-fired steam units at the West Phoenix Power Plant and refurbished the entire
fossil plant fleet during the spring of 2001 (which resulted in additional
capability of approximately 110 MW). Additionally, Pinnacle West Energy added
over 300 MW of generating capacity (including 200 MW from leased portable
generators) for the summer of 2001.
-20-
ARIZONA PUBLIC SERVICE COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
In this section, we explain our results of operations, general financial
condition, and outlook including:
* the changes in our earnings for the three-month, six-month and
twelve-month periods ended June 30, 2001 and 2000;
* the effects of regulatory agreements on our results and outlook;
* our capital needs and resources;
* major factors that affect our financial outlook; and
* our management of market risks.
We are Arizona's largest electric utility and provide retail and wholesale
electric service to the entire state with the exception of Tucson and about
one-half of the Phoenix area. We also generate and, directly or through Pinnacle
West's power marketing division, sell and deliver electricity to wholesale
customers in the western United States. Pinnacle West owns all of our
outstanding stock.
OPERATING RESULTS
The following table summarizes our revenues and earnings for the three-month,
six-month, and twelve-month periods ended June 30, 2001 and the comparable
prior-year periods:
Periods ended June 30,
(Unaudited)
(dollars in millions)
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
--------------- ----------------- ------------------
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Operating Revenues $ 841 $ 719 $1,522 $1,165 $3,837 $2,533
Earnings for Common Stock $ 70 $ 96 $ 131(1) $ 129 $ 309(1) $ 154(2)
(1) These periods include an after-tax loss related to the cumulative effect
of a change in accounting for derivatives of $3 million.
(2) The twelve-month period ended June 30, 2000 includes an after-tax
extraordinary charge of $140 million.
-21-
OPERATING RESULTS - THREE-MONTH PERIOD ENDED JUNE 30, 2001 COMPARED WITH
THREE-MONTH PERIOD ENDED JUNE 30, 2000
Earnings for the three months ended June 30, 2001 were $70 million compared
with $96 million for the same period in the prior year. The decrease in net
income of $26 million, or 27%, is primarily because of increases in purchased
power and fuel costs, higher operations and maintenance expenses, reductions in
retail electricity prices, and miscellaneous factors. The positive factors
partially offsetting these decreases were an increase in the contribution of
wholesale power marketing activities and increases in other income. See Note 6
for information on the price reductions.
Electric operating revenues increased approximately $121 million primarily
because of:
* increased power marketing revenues related to wholesale and trading
activities ($74 million);
* increased wholesale revenues primarily related to higher prices for
surplus generation sales ($35 million);
* higher retail sales volumes primarily related to weather impacts and
customer growth, partially offset by lower average usage per customer
($13 million); and
* other miscellaneous factors ($6 million).
As mentioned above, these positive factors were partially offset by
reductions in retail electricity prices ($7 million).
Purchased power and fuel expenses increased approximately $163 million
primarily because of:
* increased power marketing costs related to wholesale and trading
activities ($77 million);
* increased costs related to higher retail sales volumes primarily
related to higher purchased power and fuel prices, and weather impacts
($33 million);
* higher replacement power costs primarily for increased plant outages
($31 million);
* replacement power costs related to the Palo Verde outage extension to
replace fuel control element assemblies ($12 million); and
* a SFAS No. 133 adjustment related to changes in natural gas market
prices ($10 million).
See Notes 9 and 10 for additional information on SFAS No.133 and trading
activities.
The increase in operations and maintenance expenses primarily related to
the generation summer reliability program and increased power plant maintenance.
See Note 14 for additional information on the generation summer reliability
program.
Other net increased $9 million primarily because of insurance recovery of
environmental remediation costs.
-22-
OPERATING RESULTS - SIX-MONTH PERIOD ENDED JUNE 30, 2001 COMPARED WITH
SIX-MONTH PERIOD ENDED JUNE 30, 2000
Earnings for the six months ended June 30, 2001 were $131 million compared
with $129 million for the same period in the prior year. In January 2001, we
recognized a $3 million after-tax loss in net income as a cumulative effect of a
change in accounting for derivatives. See Notes 9 and 10 for further discussion.
Income from continuing operations increased $6 million, or 4% over the
comparable period in 2000, primarily because of increases in the contribution of
wholesale power marketing activities and a decrease in interest expense
partially offset with increases in purchased power and fuel costs, higher
operations and maintenance expenses, reductions in retail electricity prices,
and miscellaneous factors. See Note 6 for information on the price reductions.
Electric operating revenues increased approximately $357 million primarily
because of:
* increased power marketing revenues related to wholesale and trading
activities ($252 million);
* increased wholesale revenues primarily related to higher prices for
surplus generation sales ($73 million);
* higher retail sales volumes primarily related to weather impacts and
customer growth, partially offset by lower average usage per customer
($36 million); and
* other miscellaneous factors ($9 million).
As mentioned above, these positive factors were partially offset by
reductions in retail electricity prices ($13 million).
Purchased power and fuel expenses increased approximately $335 million
primarily because of:
* increased power marketing costs related to wholesale and trading
activities ($199 million);
* higher replacement power costs primarily for increased plant outages
($67 million);
* increased costs related to higher retail sales volumes primarily
attributable to higher purchased power and fuel prices and weather
impacts ($49 million);
* replacement power costs related to the Palo Verde outage extension to
replace fuel control element assemblies ($12 million); and
* SFAS No. 133 adjustments related to changes in natural gas market
prices ($8 million).
See Notes 9 and 10 for additional information on SFAS No. 133 and trading
activities.
The increase in operations and maintenance expenses primarily related to
the generation summer reliability program and increased power plant maintenance.
See Note 14 for additional information on the generation summer reliability
program.
-23-
Interest expense decreased by $7 million primarily because of lower
interest rates.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED JUNE 30, 2001 COMPARED WITH
TWELVE-MONTH PERIOD ENDED JUNE 30, 2000
Earnings for the twelve months ended June 30, 2001 were $309 million
compared with $154 million for the same period in the prior year. The increase
primarily relates to a $140 million after-tax extraordinary charge recorded in
the third quarter of 1999, partially offset by a $3 million after-tax loss for a
cumulative effect of a change in accounting for derivatives recorded in 2001.
The extraordinary charge related to a regulatory disallowance that resulted
from the 1999 Settlement Agreement that was approved by the ACC. See Notes 5 and
6 for additional information about the regulatory disallowance and the 1999
Settlement Agreement.
The cumulative effect of a change in accounting for derivatives resulted
from the implementation of SFAS No. 133. See Notes 9 and 10.
Income from continuing operations for the twelve months ended June 30, 2001
increased $19 million, or 6% over the comparable prior-year period, primarily
because of an increase in the contribution of wholesale power marketing
activities and weather impacts. These positive factors were partially offset
with higher purchased power and fuel costs, the completion of the amortization
of ITCs in 1999, higher operations and maintenance expenses, reductions in
retail electricity prices and miscellaneous factors. See Note 6 for information
on the price reductions. See "Income Taxes" below for a discussion of the ITC
amortization.
Electric operating revenues increased approximately $1.3 billion because
of:
* increased power marketing revenues related to wholesale and trading
activities ($1.11 billion);
* increased wholesale revenues primarily related to higher prices for
surplus generation sales ($126 million);
* increases in the number of customers and the average amount of
electricity used by customers ($51 million); and
* weather impacts on retail revenues ($48 million).
These positive factors were partially offset by reductions in retail
electricity prices ($28 million).
Purchased power and fuel expenses increased approximately $1.24 billion
primarily because of:
* increased power marketing costs related to wholesale and trading
activities ($1.06 billion);
* higher replacement power costs primarily for increased plant outages
($106 million);
-24-
* higher costs related to retail sales volumes and to purchased power
and fuel prices ($45 million);
* replacement power costs related to the Palo Verde outage extension to
replace fuel control element assemblies ($12 million);
* weather impacts on purchased power and fuel ($12 million); and
* an SFAS No. 133 adjustment related to changes in natural gas market
prices ($8 million).
See Notes 9 and 10 for additional information on SFAS No. 133 and trading
activities.
The increase in operations and maintenance expenses primarily related to
the generation summer reliability program and increased power plant maintenance,
offset by approximately ($14 million) of non-recurring items recorded in 1999.
See Note 14 for additional information on the generation summer reliability
program.
Interest expense decreased by $11 million primarily because of increased
capitalized interest resulting from higher construction project balances and
lower interest rates.
INCOME TAXES
As part of a 1994 rate settlement, we accelerated amortization of
substantially all of our ITCs over a five-year period that ended on December 31,
1999. The amortization of ITCs decreased annual income tax expense by
approximately $28 million. Beginning in 2000, no further benefits were being
reflected in income tax expense related to the acceleration of the ITCs.
SFAS NO. 133
The FASB has issued new guidance regarding the accounting treatment of
derivatives effective July 1, 2001. We estimate the impacts of the new guidance
are a $12 million after-tax loss in earnings and an $8 million after-tax gain in
equity (as a component of other comprehensive income). These adjustments
resulted from option contracts that did not meet the new criteria for the normal
purchases and sales exception. The impact of the new guidance will be reflected
as a cumulative effect of a change in accounting principle in the third quarter
of 2001. See Notes 9 and 10 for additional discussion of SFAS No. 133.
LIQUIDITY AND CAPITAL RESOURCES
For the six months ended June 30, 2001, we incurred approximately $231
million in capital expenditures, which is approximately 50% of the most recently
estimated 2001 capital expenditures. Our projected capital expenditures for the
next three years are $461 million in 2001; $510 million in 2002; and $321
million in 2003.
Our long-term debt redemption requirements, including optional repayments
on long-term debt are: $383 million in 2001; $125 million in 2002; and zero in
2003. During 2001, we expect to satisfy our long-term debt redemption
requirements with cash from operations and long and short-term borrowings.
Through June 2001, we redeemed $58 million of our long-term debt. Based on
market conditions and optional call provisions, we may make optional redemptions
of long-term debt from time to time.
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 our capital requirements.
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BUSINESS OUTLOOK
This section describes several major factors affecting our financial
outlook.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See "Business Outlook - Competition and Industry Restructuring" in Item 7
of the 2000 10-K and Note 6 above for a discussion of developments affecting
retail and wholesale electric competition. See Note 5 for a discussion of
regulatory accounting.
CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST
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 ISO. In April 2001, PG&E filed
for bankruptcy protection. See Note 12 for additional information.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona and in 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 3.8% a year for
the three years 1998 through 2000; we currently expect customer growth to
average 3.5% to 4% a year for 2001 through 2003. We currently estimate that
retail electricity sales in kilowatt-hours will grow 3.5% to 4.5% a year in 2001
through 2003, 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 standard offer customers that will switch to
unbundled service.
Wholesale activities will be affected by electricity prices and costs of
available purchased power and fuel in the western United States, as well as
competitive market conditions and regulatory and legislative changes in various
state and federal jurisdictions, including the price mitigation plan adopted by
FERC in June 2001 (see Note 6). These factors have significantly affected our
trading and wholesale power activities and their resultant earnings
contributions over the last several years. We cannot predict future
contributions from trading and wholesale activities. See Item 3 below for
additional information.
-26-
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
Purchased power and fuel costs are impacted by our electricity sales
volumes, existing contracts for generation purchased power and fuel, our power
plant performance, prevailing market prices, and our hedging program for
managing such costs. See "Natural Gas Supply" in Part II for additional
information on gas transportation costs.
Operations and maintenance expenses are expected to be affected by sales
mix and volumes, power plant operations, inflation, and other factors.
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. See Note 5 for the regulatory asset amortization that is
being recorded in 1999 through 2004 pursuant to the 1999 Settlement Agreement.
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. 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.
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 Notes 9 and 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 6 for a discussion of a price reduction effective as of July 1,
2001, 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.
FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current
expectations and we assume no obligation to update these statements. 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; the outcome of regulatory and
legislative proceedings relating to the restructuring; state and federal
regulatory and
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legislative decisions and actions, including the price mitigation plan adopted
by FERC in June 2001; regional economic and market conditions, including the
California energy situation, 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; 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
commodity prices, interest rates, 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 our 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 these
derivative transactions to ensure that we have enough energy for our customers
and limit our exposure to volatile wholesale prices for power and fuel. In
addition, we engage in trading activities intended to profit from favorable
movements of market prices.
As of June 30, 2001, a hypothetical adverse price movement of 10% in the
market price of our commodity derivative portfolio would decrease the fair
market value of these contracts by approximately $46 million. This analysis does
not include the favorable impact this same hypothetical price move would have on
the underlying physical exposures being hedged with the commodity derivative
portfolio. We plan to complete the move of our wholesale power marketing and
trading activities to the parent company by the end of 2002.
We are exposed to credit losses in the event of non-performance or
non-payment by counterparties. We use a credit management process to assess and
monitor the financial exposure of counterparties. Despite the fact that the
great majority of our 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.
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.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As previously reported, in June 1999, the Navajo Nation served Salt River
Project with a lawsuit naming Salt River Project, several Peabody Coal Company
entities, SCE and other defendants, and citing various claims in connection with
the renegotiations of the coal royalty and lease agreements under which Peabody
mines coal for Navajo Generating Station and the Mohave Generating Station. THE
NAVAJO NATION V. PEABODY HOLDING COMPANY, INC., et al., United States District
Court for the District of Columbia, CA-99-0469-EGS. We are a 14% owner of the
Navajo Generating Station, which Salt River Project operates. See "Legal
Proceedings" in Item 3 of the 2000 10-K. In July 2001, the court dismissed all
claims against Salt River Project.
See Note 13 of Notes to Condensed Financial Statements for additional
matters.
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 our construction and financing programs.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 6 of Notes to Condensed Financial Statements in Part I, Item 1 of
this report for a discussion of competition and the rules regarding the
introduction of retail electric competition in Arizona and a settlement
agreement with the ACC.
WATER SUPPLY
A summons served on us in early 1986 required all water claimants in the
Lower Gila River Watershed in Arizona to assert any claims to water on or before
January 20, 1987. See "Water Supply" in Part II, Item 5 of the March 2001 10-Q.
We and other parties petitioned the U.S. Supreme Court for review of the Arizona
Supreme Court's decision affirming the lower court's criteria for resolving
groundwater claims, and that petition was denied.
TAX WAIVER
The lease for the Four Corners plant site waived, until July 2001, the
requirement that the coal supplier and vendors pay certain taxes to the Navajo
Nation. The coal supplier currently pays a possessory interest tax (PIT) and
business activity tax (BAT) to the Navajo Nation, which is reimbursed by the
Four Corners participants, including us. The PIT is due from the coal supplier,
one half on November 1 and one half on May 1 of each year, beginning on November
1, 2001, and the BAT is due from the coal supplier 45 days after the calendar
quarter ends, beginning November 15, 2001. We anticipate that the Navajo Nation
will levy additional taxes; however, we cannot currently predict the outcome of
this
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matter or the amount of any additional taxes. The coal supplier, the Navajo
Nation and the Four Corners participants are continuing to investigate
alternative contractual arrangements and business relationships in an effort to
permit the electricity generated at Four Corners to be priced competitively.
PURPORTED NAVAJO ENVIRONMENTAL REGULATIONS
As previously reported, on July 12, 2000, the Four Corners participants and
the Navajo Generating Station participants each filed a petition with the Navajo
Supreme Court for review of the operating permit regulations. See "Purported
Navajo Environmental Regulations" in Part I, Item 1 of the 2000 10-K. The Navajo
Nation and the Four Corners and Navajo Generating Station participants agreed to
indefinitely stay this proceeding so that the parties may attempt to resolve the
dispute without litigation. The Court has stayed this proceeding pursuant to a
request by the parties. We cannot currently predict the outcome of this matter.
NATURAL GAS SUPPLY
The gas supply for the Company and Pinnacle West Energy gas-fired
facilities located, and to be located (see Note 12), in Pinal, Maricopa and Yuma
counties in Arizona, is transported pursuant to a firm, Full Requirements
Transportation Service Agreement with El Paso Natural Gas Company. The
transportation agreement features a 10 year rate moratorium established in a
comprehensive rate case settlement entered into in 1996.
In a pending FERC proceeding, El Paso 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.
Various parties, including us and Pinnacle West Energy, have challenged this
allocation as being inconsistent with El Paso's existing contractual obligations
and the 1996 settlement. At this time, there are ongoing discussions among FERC,
El Paso and other affected parties to resolve these issues. We cannot currently
predict the outcome of this matter.
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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:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.1 Articles of Incorporation 4.2 to Form S-3 Registration 1-4473 9-29-93
restated as of May 25, 1988 Nos. 33-33910 and 33-55248
by means of September 24,
1993 Form 8-K Report
10.2 Bylaws, amended as of 3.1 to 1995 Form 10-K Report 1-4473 3-29-96
February 20, 1996
(b) Reports on Form 8-K
During the quarter ended June 30, 2001, and the period from July 1 through
August 14, 2001, we filed the following reports on Form 8-K:
Report dated April 5, 2001, regarding the Arizona Court of Appeals
affirming the ACC approval of the 1999 Settlement Agreement.
- ----------
(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.
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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 14, 2001 By: Michael V. Palmeri
-------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)