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 March 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission file number 1-4473
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)
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 May 15, 2000: 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
Company - Arizona Public Service Company
DOE - United States Department of Energy
EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the
Pricing of Electricity -- Issues Related to the Application of FASB Statements
No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises -- Accounting for the Discontinuation of Application of
FASB Statement No. 71"
EPA - Environmental Protection Agency
FERC - Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
ITC - Investment tax credit
MW - Megawatts
NGS - Navajo Generating Station
1999 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 1999
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"
SFAS No. 133 - Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities"
Salt River Project - Salt River Project Agricultural Improvement and Power
District
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended March 31,
----------------------
2000 1999
--------- ---------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ........................... $ 445,981 $ 413,983
--------- ---------
FUEL EXPENSES:
Fuel for electric generation ........................ 58,811 52,116
Purchased power ..................................... 66,953 48,229
--------- ---------
Total ............................................ 125,764 100,345
--------- ---------
OPERATING REVENUES LESS FUEL EXPENSES ................. 320,217 313,638
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel
expenses.......................................... 108,528 100,262
Depreciation and amortization ....................... 95,947 96,139
Income taxes ........................................ 24,267 24,803
Other taxes ......................................... 25,381 25,478
--------- ---------
Total ............................................ 254,123 246,682
--------- ---------
OPERATING INCOME ...................................... 66,094 66,956
--------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net ......................................... 1,628 (2,934)
Income taxes ........................................ (675) 4,256
--------- ---------
Total ............................................ 953 1,322
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS ..................... 67,047 68,278
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt .......................... 33,338 33,556
Interest on short-term borrowings ................... 1,267 2,068
Debt discount, premium and expense .................. 1,893 1,845
Capitalized interest ................................ (2,226) (2,986)
--------- ---------
Total ............................................ 34,272 34,483
--------- ---------
NET INCOME ............................................ 32,775 33,795
PREFERRED STOCK DIVIDEND REQUIREMENTS ................. -- 1,016
--------- ---------
EARNINGS FOR COMMON STOCK ............................. $ 32,775 $ 32,779
========= =========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended March 31,
--------------------------
2000 1999
----------- -----------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ....................... $ 2,324,795 $ 2,039,958
----------- -----------
FUEL EXPENSES:
Fuel for electric generation .................... 250,544 233,755
Purchased power ................................. 570,369 336,940
----------- -----------
Total ........................................ 820,913 570,695
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES ............. 1,503,882 1,469,263
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel ....... 446,008 420,820
Depreciation and amortization ................... 381,865 380,566
Income taxes .................................... 191,479 192,546
Other taxes ..................................... 96,469 101,105
----------- -----------
Total ........................................ 1,115,821 1,095,037
----------- -----------
OPERATING INCOME .................................. 388,061 374,226
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net ..................................... (6,975) (12,841)
Income taxes .................................... 27,597 32,552
----------- -----------
Total ........................................ 20,622 19,711
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................. 408,683 393,937
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ...................... 132,458 135,587
Interest on short-term borrowings ............... 7,471 8,865
Debt discount, premium and expense .............. 7,371 7,476
Capitalized interest ............................ (5,919) (15,098)
----------- -----------
Total ........................................ 141,381 136,830
----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE ................ 267,302 257,107
Extraordinary charge - net of income
taxes of $94,115 .............................. 139,885 --
----------- -----------
NET INCOME ........................................ 127,417 257,107
PREFERRED STOCK DIVIDEND REQUIREMENTS ............. -- 7,841
----------- -----------
EARNINGS FOR COMMON STOCK ......................... $ 127,417 $ 249,266
=========== ===========
See Notes to Condensed Financial Statements
-4-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Unaudited)
March 31, December 31,
2000 1999
----------- -----------
(Thousands of Dollars)
UTILITY PLANT:
Electric plant in service and held for
future use ........................................ $ 7,610,576 $ 7,545,575
Less accumulated depreciation and amortization ..... 3,082,572 3,026,041
----------- -----------
Total ........................................... 4,528,004 4,519,534
Construction work in progress ...................... 181,801 184,764
Nuclear fuel, net of amortization .................. 52,390 49,114
----------- -----------
Utility plant - net ............................. 4,762,195 4,753,412
----------- -----------
INVESTMENTS AND OTHER ASSETS ....................... 213,411 208,457
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents .......................... 110,624 7,477
Accounts receivable:
Service customers ............................... 149,668 201,704
Other ........................................... 43,023 35,684
Allowance for doubtful accounts ................. (1,776) (1,538)
Accrued utility revenues ........................... 63,093 72,919
Materials and supplies, at average cost ............ 73,779 69,977
Fossil fuel, at average cost ....................... 21,260 21,869
Deferred income taxes .............................. 8,163 8,163
Other .............................................. 34,828 30,885
----------- -----------
Total current assets ............................ 502,662 447,140
----------- -----------
DEFERRED DEBITS:
Regulatory assets .................................. 580,158 613,729
Unamortized debt issue costs ....................... 14,788 15,172
Other .............................................. 73,561 79,714
----------- -----------
Total deferred debits ........................... 668,507 708,615
----------- -----------
TOTAL ........................................... $ 6,146,775 $ 6,117,624
=========== ===========
See Notes to Condensed Financial Statements.
-5-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Unaudited)
March 31, December 31,
2000 1999
---------- ----------
(Thousands of Dollars)
CAPITALIZATION:
Common stock ....................................... $ 178,162 $ 178,162
Additional paid-in capital ......................... 1,246,804 1,246,804
Retained earnings .................................. 505,982 558,208
---------- ----------
Common stock equity ............................. 1,930,948 1,983,174
Long-term debt less current maturities ............. 1,807,952 1,997,400
---------- ----------
Total capitalization ............................ 3,738,900 3,980,574
---------- ----------
CURRENT LIABILITIES:
Commercial paper ................................... 128,800 38,300
Current maturities of long-term debt ............... 215,261 114,711
Accounts payable ................................... 119,467 170,662
Accrued taxes ...................................... 123,302 62,858
Accrued interest ................................... 17,482 32,299
Common dividends payable ........................... 85,000 --
Customer deposits .................................. 24,570 24,682
Other .............................................. 41,727 26,248
---------- ----------
Total current liabilities ....................... 755,609 469,760
---------- ----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes .............................. 1,167,569 1,178,085
Unamortized gain - sale of utility plant ........... 72,068 73,212
Customer advances for construction ................. 38,606 38,150
Other .............................................. 374,023 377,843
---------- ----------
Total deferred credits and other ................ 1,652,266 1,667,290
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 6, 7 and 9)
TOTAL ........................................... $6,146,775 $6,117,624
========== ==========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months
Ended March 31,
----------------------
2000 1999
--------- ---------
(Thousands of Dollars)
Cash Flows from Operating Activities:
Net income .......................................... $ 32,775 $ 33,795
Items not requiring cash:
Depreciation and amortization ..................... 95,947 96,139
Nuclear fuel amortization ......................... 7,931 8,269
Deferred income taxes - net ....................... (7,058) (7,193)
Changes in certain current assets and liabilities:
Accounts receivable - net ......................... 44,935 23,981
Accrued utility revenues .......................... 9,826 8,804
Materials, supplies and fossil fuel ............... (3,193) (1,189)
Other current assets .............................. (3,943) (1,384)
Accounts payable .................................. (51,087) (49,632)
Accrued taxes ..................................... 60,444 54,797
Accrued interest .................................. (14,817) (4,714)
Other current liabilities ......................... 15,367 9,711
Other - net ......................................... 1,901 (6,305)
--------- ---------
Net cash flow provided by operating
activities ..................................... 189,028 165,079
--------- ---------
Cash Flows from Investing Activities:
Capital expenditures ................................ (82,342) (67,467)
Capitalized interest ................................ (2,226) (2,986)
Other ............................................... (2,675) (2,629)
--------- ---------
Net cash flow used for investing activities ..... (87,243) (73,082)
--------- ---------
Cash Flows from Financing Activities:
Long-term debt ...................................... -- 124,189
Short-term borrowings - net ......................... 90,500 (66,105)
Dividends paid on common stock ...................... -- (42,500)
Dividends paid on preferred stock ................... -- (1,393)
Repayment of preferred stock ........................ -- (96,499)
Repayment and reacquisition of long-term debt ....... (89,138) (10,070)
--------- ---------
Net cash flow provided (used) for
financing activities .......................... 1,362 (92,378)
--------- ---------
Net increase (decrease) in cash and cash equivalents .. 103,147 (381)
Cash and cash equivalents at beginning of period ...... 7,477 5,558
--------- ---------
Cash and cash equivalents at end of period ............ $ 110,624 $ 5,177
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) $ 31,932 $ 37,294
Income taxes $ -- $ --
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 extraordinary item. 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 1999 10-K. We have reclassified certain prior year
amounts to conform to the current year presentation.
2. Weather conditions can have a significant impact on our results for interim
periods. For this and other reasons, 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 three months ended March 31, 2000.
5. Regulatory Accounting
For regulated operations, we prepare our financial statements in accordance with
Statement of Financial Accounting Standards (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 Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (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.
In September 1999, our Settlement Agreement (Settlement Agreement) was approved
by the ACC (see Note 6 for a discussion of the agreement). We have discontinued
the application of SFAS No. 71 for our generation operations. This means that
the generation assets were tested for impairment and the portion of regulatory
assets deemed to be unrecoverable through ongoing regulated cash flows was
eliminated. We determined that the generation assets were not impaired. A
regulatory disallowance removed $234 million pretax ($183 million net present
value) from ongoing regulatory
-8-
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
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.
The regulatory assets to be recovered under the 1999 Settlement Agreement are
now being amortized as follows (millions of dollars):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
The majority of our 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 (thousands of dollars):
March 31, December 31,
2000 1999
----------- -----------
Electric plant in service & held for future use $ 3,767,769 $ 3,770,234
Accumulated depreciation and amortization (1,845,080) (1,817,589)
Construction work in progress 68,652 67,306
Nuclear fuel, net of amortization 52,390 49,114
6. Regulatory Matters -- Electric Industry Restructuring
STATE
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 Settlement Agreement, with
some modifications. On December 13, 1999, two parties filed lawsuits challenging
the ACC's approval of the Settlement Agreement. One of the parties questioned
the authority of the ACC to approve the Settlement Agreement and both parties
challenged several specific provisions of the Settlement Agreement.
-9-
The following are the major provisions of the Settlement Agreement, as approved:
* We will reduce rates for standard offer service for customers with
loads less than 3 megawatts in a series of annual retail electric
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 the July 1, 1999 retail
price decrease of approximately $11 million annually ($7 million after
income taxes) related to the 1996 regulatory agreement. See "1996
Regulatory Agreement" below. For customers having loads 3 megawatts or
greater, standard offer rates will be reduced in annual increments
that total 5% through 2002.
* Unbundled rates being charged by us for competitive direct access
service (for example, distribution services) became effective upon
approval of the Settlement Agreement, retroactive to July 1, 1999, and
also will be 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 current
rates, and costs associated with our "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 will be 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), with an
additional 140 megawatts being made available to eligible
non-residential customers. Unless subject to judicial or regulatory
restraint, we will open our distribution system to retail access for
all customers on January 1, 2001.
* Prior to the Settlement Agreement, we were recovering substantially
all of our regulatory assets through July 1, 2004, pursuant to the
1996 regulatory agreement. In addition, the Settlement Agreement
states that we have
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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 Settlement Agreement provides that we
will have the opportunity to recover $350 million net present value
through a competitive transition charge (CTC) that will remain in
effect through December 31, 2004, at which time it will terminate. Any
over/under-recovery will be credited/debited against the costs subject
to recovery under the adjustment clause described above.
* We will form a separate corporate affiliate or affiliates and transfer
to that affiliate(s) our generating assets and competitive services at
book value as of the date of transfer, which transfer shall take place
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.
* When the 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 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.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve the rules that provide a framework for the introduction of retail
electric competition in Arizona (Rules). If any of the Rules conflict with the
Settlement Agreement, the terms of the Settlement Agreement govern. 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 and the adoption or amendment of the Rules,
but two related cases filed by other utilities have been partially decided in a
manner adverse to those utilities' positions. On January 14, 2000, a special
action was filed requesting the Arizona Supreme Court to enjoin implementation
of the Rules and decide whether the ACC can allow the competitive marketplace,
rather than the ACC, to set just and reasonable rates under the Arizona
Constitution. The issue of competitively set rates has been decided by lower
Arizona courts in favor of the ACC in four separate lawsuits, two of which
relate to telecommunications companies. The Supreme Court denied to hear the
case as a special action on March 17, 2000. The lower court litigation will
continue.
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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.
* The Rules require each affected utility, including us, to make
available at least 20% of its 1995 system retail peak demand for
competitive generation supply beginning when the ACC makes a final
decision on each utility's stranded costs and unbundled rates (Final
Decision Date) or January 1, 2001, whichever is earlier, and 100%
beginning January 1, 2001. Under the Settlement Agreement, we will
provide retail access to customers representing the minimum 20%
required by the ACC and an additional 140 megawatts of non-residential
load in 1999, and to all customers as of January 1, 2001, or such
other dates as approved by the ACC.
* Subject to the 20% requirement, all utility customers with single
premise loads of one megawatt or greater will be eligible for
competitive electric services on the Final Decision Date, which for
our customers was the approval of the Settlement Agreement. Customers
may also aggregate smaller loads to meet this one megawatt
requirement.
* When effective, residential customers will be phased in at 1.25% per
quarter calculated beginning on January 1, 1999, subject to the 20%
requirement above.
* Electric service providers that get Certificates of Convenience and
Necessity (CC&Ns) 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 Settlement Agreement, we
received a waiver to allow transfer of our competitive generation
assets and services to affiliates no later than December 31, 2002.
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 of
approximately $49 million ($29 million after income taxes), or 3.4%, effective
July 1, 1996; approximately $18 million ($11 million after income taxes), or
1.2%, effective July 1,
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1997; approximately $17 million ($10 million after income taxes), or 1.1%,
effective July 1, 1998; and approximately $11 million ($7 million after income
taxes), or 0.7%, effective as of July 1, 1999. The July 1, 1999 rate decrease
was included in the first rate reduction under the Settlement Agreement
discussed above. The regulatory agreement also required Pinnacle West 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 megawatt (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, or results of operation. 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 Energy Policy Act of 1992 and recent rulemakings by FERC have promoted
increased competition in the wholesale electric power markets. We do not expect
these rules to have a material impact on our financial statements.
Several electric utility industry restructuring bills have been introduced
during the 106th Congress. Several of these bills are written to allow consumers
to choose their electricity suppliers beginning in 2000 and beyond. These bills,
other bills that are
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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.
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 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.
-14-
8. Business Segments
We have two principal business segments (determined by products, services and
regulatory environment) which consist of the generation of electricity
(generation business segment) and the transmission and distribution of
electricity (delivery business segment). Eliminations primarily relate to
intersegment sales of electricity. Segment information for the three and twelve
months ended March 31, 2000, and 1999 is as follows (millions of dollars):
3 Months Ended 12 Months Ended
March 31, March 31,
------------------ ------------------
2000 1999 2000 1999
------- ------- ------- -------
Operating Revenues:
Generation $ 181 $ 178 $ 858 $ 856
Delivery 446 414 2,325 2,040
Eliminations (181) (178) (858) (856)
------- ------- ------- -------
Total $ 446 $ 414 $ 2,325 $ 2,040
======= ======= ======= =======
Earnings excluding Extraordinary
Charge:
Generation $ 8 $ 11 $ 118 $ 113
Delivery 25 22 149 136
------- ------- ------- -------
Total $ 33 $ 33 $ 267 $ 249
======= ======= ======= =======
As of March 31, As of December 31,
2000 1999
------- -------
Assets:
Generation $ 2,302 $ 2,322
Delivery 3,845 3,796
------- -------
Total $ 6,147 $ 6,118
======= =======
9. Accounting Matters
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which is
effective for us in 2001. 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. The standard also provides specific guidance
for accounting for derivatives designated as hedging instruments. We are
currently evaluating what impact this standard will have on our financial
statements.
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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 periods presented
* the factors impacting our business, including competition
* the effects of regulatory agreements on our results and outlook
* our capital needs and resources, and
* our management of market risks.
We are Arizona's largest electric utility, providing wholesale and retail
electric service to the entire state with the exception of Tucson and about
one-half of the Phoenix area. We also generate, sell, and deliver electricity
and energy-related products and services to wholesale and retail customers in
the western United States.
We suggest this section be read along with the 1999 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. These Notes add further details to the discussion.
OPERATING RESULTS
The following table summarizes our revenues and earnings for the three-month and
twelve-month periods ended March 31, 2000 and 1999:
Periods ended March 31
(Unaudited)
(Thousands of Dollars)
Three Months Twelve Months
----------------------- --------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
Operating Revenues $ 445,981 $ 413,983 $2,324,795 $2,039,958
Earnings for Common Stock $ 32,775 $ 32,779 $ 127,417(1) $ 249,266
(1) The twelve months ended March 31, 2000 period includes an extraordinary
charge of $139,885 net of income taxes of $94,115.
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OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2000 COMPARED WITH
THREE-MONTH PERIOD ENDED MARCH 31, 1999
First quarter earnings were flat at $33 million in the three-month comparison.
Increased revenue related to customer growth was offset by higher utility
operations and maintenance expenses; a reduction in retail electricity prices;
and the completion of the amortization of investment tax credits in 1999. See
Note 6 for information on the price reduction. See "Income Taxes" for a
discussion of the investment tax credit amortization.
Electric operating revenues increased $32 million because of:
* increased power marketing and trading revenues ($23 million) and
* increases in the number of customers ($15 million).
As mentioned above, these positive factors were partially offset by the effect
of a reduction in retail electricity prices ($5 million) and miscellaneous
factors ($1 million).
The increase in power marketing revenues resulted from higher prices and
increased activity in the western U.S. bulk power markets. The revenues were
accompanied by an increase in purchased power and fuel expenses. Although these
activities contributed positively to earnings in both periods, the contribution
in 2000 was modestly lower than in 1999.
Utility operations and maintenance expense increased primarily due to the timing
of customer related expenses.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2000 COMPARED WITH
TWELVE-MONTH PERIOD MARCH 31, 1999
Earnings for the twelve months ended March 31, 2000 were $127 million compared
with $249 million for the same period in the prior year. The decrease primarily
relates to an extraordinary charge recorded in the third quarter of 1999,
partially offset by higher income excluding the extraordinary charge.
The extraordinary charge related to a regulatory disallowance that resulted from
our comprehensive Settlement Agreement that was approved by the ACC in September
1999. See Notes 5 and 6 for additional information about the regulatory
disallowance and the Settlement Agreement.
Earnings excluding the extraordinary charge increased $18 million over the
comparable period primarily because of increases in the number of customers and
in the average amount of electricity used by customers; and favorable weather
impacts. These positive factors more than offset higher utility operations and
maintenance expense, a reduction in retail electricity prices, and the
completion of the amortization of investment
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tax credits in 1999. See Note 6 for information on the price reduction. See
"Income Taxes" below for a discussion of the investment tax credit amortization.
Electric operating revenues increased $285 million because of:
* increased power marketing and trading revenues ($209 million)
* increases in the number of customers and the average amount of
electricity used by customers ($82 million)
* favorable weather impacts ($10 million) and
* miscellaneous factors ($8 million).
As mentioned above, these positive factors were partially offset by the effect
of a reduction in retail prices ($24 million).
The increase in power marketing revenues resulted primarily from increased
activity in western bulk power markets and higher prices. The revenues were
accompanied by increases in purchased power and fuel expenses. Although these
activities contributed positively to earnings in both periods, the contribution
in the current period was modestly lower than the prior period. Fuel expenses
were also higher because of increased fuel prices and higher retail sales
volumes.
Utility operations and maintenance expenses increased primarily because of $19
million of non-recurring items recorded in the current period, including a
provision for certain environmental costs. Other increases primarily related to
customer growth, power marketing costs, and technology related costs were
partially offset by the movement of certain marketing functions to APS Energy
Services.
INCOME TAXES
As part of a 1994 rate settlement with the ACC, we accelerated amortization of
substantially all deferred ITCs over a five-year period that ended on December
31, 1999. It decreased annual income tax expense by approximately $28 million.
Beginning in 2000, no further benefits from these deferred ITCs will be
reflected in income tax expense.
LIQUIDITY AND CAPITAL RESOURCES
For the three months ended March 31, 2000, we incurred approximately $81 million
in capital expenditures, which is approximately 21% of the most recently
estimated 2000 capital expenditures. Our projected capital expenditures for the
next three years are $384 million in 2000; $342 million in 2001; and $334
million in 2002. These amounts include about $30 - $35 million each year for
nuclear fuel expenditures.
Our long-term debt redemption requirements, optional repayments on long-term
debt, and payment obligations on a capitalized lease for the next three years
are: $304 million in 2000; $252 million in 2001; and $125 million in 2002.
During the three months
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ended March 31, 2000, we redeemed approximately $89 million of our long-term
debt with cash from operations and long- and short-term debt. On May 15, 2000,
we will redeem approximately $100 million of our First Mortgage Bonds, 10.25%
Series due 2020.
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.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 for a discussion of regulatory accounting. See Note 6 for a
discussion of a Settlement Agreement related to the implementation of retail
electric competition.
RATE MATTERS
See Note 6 for a discussion of a price reduction effective as of July 1, 1999,
and for a discussion of a Settlement Agreement that will, among other things,
result in five price reductions over a four-year period ending July 1, 2003.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax, and environmental
legislation; our ability to successfully compete outside traditional regulated
markets; regional economic conditions, which could affect customer growth; the
cost of debt and equity capital; weather variations affecting customer usage;
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 the nuclear decommissioning
trust fund.
Our major financial market risk exposure is changing interest rates. Changing
interest rates will affect interest paid on variable-rate debt and interest
earned by the nuclear decommissioning trust fund. Our policy is to manage
interest rates through the use of a
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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.
We are exposed to the impact of market fluctuations in the price and
distribution 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 for trading and to hedge certain natural gas in storage
as well as purchases and sales of electricity, fuels, and emissions
allowances/credits.
As of March 31, 2000, 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 $17 million. This analysis does not include
the favorable impact this same hypothetical price move would have on the
underlying positions being hedged with the commodity derivative portfolio.
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. We do not expect counterparty defaults to
materially impact our financial condition, results of operations or net cash
flow.
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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 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.
ENVIRONMENTAL MATTERS
As previously reported, in April 1998 we filed a Petition for Review regarding
EPA's regulations specifying those provisions of the Clean Air Act for which it
is appropriate to treat Indian Tribes in the same manner as states. See
"Environmental Matters - Purported Navajo Environmental Regulation" in Part I,
Item 1 of our 1999 Form 10-K. Partly in response to the litigation, EPA
indicated it had not determined whether the Clean Air Act would supersede
pre-existing binding agreements involving Four Corners and NGS. On May 5, 2000,
the United States Court of Appeals for the District of Columbia upheld EPA's
regulations on treatment of Indian Tribes in the same manner as states. However,
the Court determined that the impact of this ruling on the pre-existing binding
agreements involving Four Corners and NGS was not ripe for adjudication because
EPA had not made a determination that the Clean Air Act superseded those
agreements. We cannot currently predict the outcome of this matter.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
12.1 Computation of Ratio of Earnings to Fixed Charges
27.1 Financial Data Schedule
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In addition to those Exhibits shown above, 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
- ----------- ----------- ---------------------------- ----------- --------------
3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96
February 20, 1996 Report
3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, 1988 Registration Nos.
33-33910 and 33-55248 by
means of September 24,
1993 Form 8-K Report
(b) Reports on Form 8-K
During the quarter ended March 31, 2000, and the period from April 1
through May 15, 2000, we did not file any reports on Form 8-K.
- ----------
(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: May 15, 2000 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Financial Officer
and Officer Duly Authorized
to sign this Report)