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, 1999
---------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from _____________ to _____________
Commission file number 1-4473
------------
ARIZONA PUBLIC SERVICE COMPANY
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Arizona 86-0011170
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999
- -------------------------------------------------------- -------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (602) 250-1000
-------------------
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Number of shares of common stock, $2.50 par value,
outstanding as of May 17, 1999: 71,264,947
<PAGE>
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 - Emerging Issues Task Force
EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the
Pricing of Electricity -- Issues Related to the Applications 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"
EITF 98-10 - Emerging Issues Task Force Issue No. 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities"
FERC - Federal Energy Regulatory Commission
ITC - Investment tax credit
1998 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 1998
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
Power Coordination Agreement - 1955 agreement between the Company and Salt River
Project that provides for certain electric system and power sales
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
Territorial Agreement - 1955 agreement between the Company and Salt River
Project that has provided exclusive retail service territories in Arizona for
each party
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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,
1999 1998
--------- ---------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ............................ $ 413,983 $ 380,423
--------- ---------
FUEL EXPENSES:
Fuel for electric generation ......................... 52,116 50,328
Purchased power ...................................... 47,125 23,589
--------- ---------
Total ............................................. 99,241 73,917
--------- ---------
OPERATING REVENUES LESS FUEL EXPENSES .................. 314,742 306,506
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses.... 97,404 96,416
Depreciation and amortization ........................ 96,139 92,147
Income taxes ......................................... 24,803 24,464
Other taxes .......................................... 29,440 29,938
--------- ---------
Total ............................................. 247,786 242,965
--------- ---------
OPERATING INCOME ....................................... 66,956 63,541
--------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net .......................................... (2,934) (2,396)
Income taxes ......................................... 4,256 4,455
--------- ---------
Total ............................................. 1,322 2,059
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS ...................... 68,278 65,600
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................... 33,556 35,183
Interest on short-term borrowings .................... 2,068 684
Debt discount, premium and expense ................... 1,845 1,949
Capitalized interest ................................. (2,986) (4,151)
--------- ---------
Total ............................................. 34,483 33,665
--------- ---------
NET INCOME ............................................. 33,795 31,935
PREFERRED STOCK DIVIDEND REQUIREMENTS .................. 1,016 2,878
--------- ---------
EARNINGS FOR COMMON STOCK .............................. $ 32,779 $ 29,057
========= =========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
TWELVE MONTHS
ENDED MARCH 31,
1999 1998
----------- -----------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES .................... $ 2,039,958 $ 1,879,955
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ................. 233,755 200,547
Purchased power .............................. 329,070 224,528
----------- -----------
Total ..................................... 562,825 425,075
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES .......... 1,477,133 1,454,880
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel
expenses ................................... 415,029 407,834
Depreciation and amortization ................ 380,566 365,803
Income taxes ................................. 192,546 186,909
Other taxes .................................. 114,766 120,407
----------- -----------
Total ..................................... 1,102,907 1,080,953
----------- -----------
OPERATING INCOME ............................... 374,226 373,927
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net .................................. (12,841) (10,014)
Income taxes ................................. 32,552 31,528
----------- -----------
Total ..................................... 19,711 21,514
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS .............. 393,937 395,441
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ................... 135,587 141,685
Interest on short-term borrowings ............ 8,865 7,760
Debt discount, premium and expense ........... 7,476 7,738
Capitalized interest ......................... (15,098) (16,525)
----------- -----------
Total ..................................... 136,830 140,658
----------- -----------
NET INCOME ..................................... 257,107 254,783
PREFERRED STOCK DIVIDEND REQUIREMENTS .......... 7,841 12,055
----------- -----------
EARNINGS FOR COMMON STOCK ...................... $ 249,266 $ 242,728
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Unaudited)
MARCH 31, DECEMBER 31,
1999 1998
----------- -----------
(Thousands of Dollars)
UTILITY PLANT:
Electric plant in service and held for future use $ 7,299,849 $ 7,265,604
Less accumulated depreciation and amortization ... 2,886,117 2,814,762
----------- -----------
Total ......................................... 4,413,732 4,450,842
Construction work in progress .................... 242,084 228,643
Nuclear fuel, net of amortization ................ 57,386 51,078
----------- -----------
Utility plant - net ........................... 4,713,202 4,730,563
----------- -----------
INVESTMENTS AND OTHER ASSETS ..................... 202,254 183,549
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents ........................ 5,177 5,558
Accounts receivable:
Service customers ............................. 157,502 205,999
Other ......................................... 47,812 23,213
Allowance for doubtful accounts ............... (1,808) (1,725)
Accrued utility revenues ......................... 58,936 67,740
Materials and supplies, at average cost .......... 71,232 69,074
Fossil fuel, at average cost ..................... 13,009 13,978
Deferred income taxes ............................ 3,999 3,999
Other ............................................ 28,079 26,695
----------- -----------
Total current assets .......................... 383,938 414,531
----------- -----------
DEFERRED DEBITS:
Regulatory asset for income taxes ................ 387,616 400,795
Rate synchronization cost deferral ............... 289,857 303,660
Unamortized costs of reacquired debt ............. 51,118 53,744
Unamortized debt issue costs ..................... 15,617 14,916
Other ............................................ 295,085 291,541
----------- -----------
Total deferred debits ......................... 1,039,293 1,064,656
----------- -----------
TOTAL ......................................... $ 6,338,687 $ 6,393,299
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES
(Unaudited)
March 31, December 31,
1999 1998
---------- ------------
(Thousands of Dollars)
CAPITALIZATION:
Common stock ..................................... $ 178,162 $ 178,162
Additional paid-in capital ....................... 1,195,625 1,195,625
Retained earnings ................................ 549,746 601,968
---------- ----------
Common stock equity ........................... 1,923,533 1,975,755
Non-redeemable preferred stock ................... -- 85,840
Redeemable preferred stock ....................... -- 9,401
Long-term debt less current maturities ........... 2,001,586 1,876,540
---------- ----------
Total capitalization .......................... 3,925,119 3,947,536
---------- ----------
CURRENT LIABILITIES:
Commercial paper ................................. 112,725 178,830
Current maturities of long-term debt ............. 154,378 164,378
Accounts payable ................................. 96,503 145,139
Accrued taxes .................................... 114,624 59,827
Accrued interest ................................. 26,504 31,218
Common dividends payable ......................... 42,500 --
Customer deposits ................................ 26,770 26,815
Other ............................................ 26,038 16,755
---------- ----------
Total current liabilities ..................... 600,042 622,962
---------- ----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ............................ 1,303,935 1,312,007
Deferred investment tax credit ................... 29,385 32,465
Unamortized gain - sale of utility plant ......... 76,643 77,787
Customer advances for construction ............... 34,397 31,451
Other ............................................ 369,166 369,091
---------- ----------
Total deferred credits and other .............. 1,813,526 1,822,801
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 5, 8, and 9)
TOTAL ......................................... $6,338,687 $6,393,299
========== ==========
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,
1999 1998
--------- ---------
(Thousands of Dollars)
Cash Flows from Operating Activities:
Net income ......................................... $ 33,795 $ 31,935
Items not requiring cash:
Depreciation and amortization .................... 96,139 92,147
Nuclear fuel amortization ........................ 8,269 8,417
Deferred income taxes - net ...................... (7,193) (7,010)
Deferred investment tax credit - net ............. (3,080) (3,454)
Changes in certain current assets and liabilities:
Accounts receivable - net ........................ 23,981 41,923
Accrued utility revenues ......................... 8,804 9,028
Materials, supplies and fossil fuel .............. (1,189) (3,501)
Other current assets ............................. (1,384) (2,484)
Accounts payable ................................. (49,632) (33,020)
Accrued taxes .................................... 54,797 55,262
Accrued interest ................................. (4,714) (5,413)
Other current liabilities ........................ 9,711 7,528
Other - net ........................................ (3,225) 11,316
--------- ---------
Net cash flow provided by operating activities ....... 165,079 202,674
--------- ---------
Cash Flows from Investing Activities:
Capital expenditures ............................... (67,467) (60,848)
Capitalized interest ............................... (2,986) (4,151)
Other .............................................. (2,629) (119)
--------- ---------
Net cash flow used for investing activities .... (73,082) (65,118)
--------- ---------
Cash Flows from Financing Activities:
Long-term debt ..................................... 124,189 99,375
Short-term borrowings - net ........................ (66,105) (49,750)
Dividends paid on common stock ..................... (42,500) (42,500)
Dividends paid on preferred stock .................. (1,393) (2,964)
Repayment of preferred stock ....................... (96,499) (10,599)
Repayment and reacquisition of long-term debt ...... (10,070) (134,734)
--------- ---------
Net cash flow used for financing activities .... (92,378) (141,172)
--------- ---------
Net increase (decrease) in cash and cash equivalents . (381) (3,616)
Cash and cash equivalents at beginning of period ..... 5,558 12,552
--------- ---------
Cash and cash equivalents at end of period ........... $ 5,177 $ 8,936
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........ $ 37,294 $ 37,072
Income taxes ..................................... $ -- $ 1,250
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. Our 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. 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 1998 10-K. We have
reclassified certain prior year amounts for comparison purposes with 1999.
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, 1999.
5. Regulatory Matters -- Electric Industry Restructuring
STATE
PROPOSED RETAIL ELECTRIC COMPETITION RULES. In December 1996, the ACC
adopted rules that provide a framework for the introduction of retail electric
competition in Arizona. The rules, as amended, became effective on August 10,
1998, and on December 10, 1998, the ACC adopted the amended rules without any
modifications that would have a significant impact on us. We believe that
certain provisions of the 1996 ACC rules and the amended rules are deficient and
we have filed lawsuits to protect our legal rights regarding the 1996 rules and
the amended rules. These lawsuits are pending but two related cases filed by
other utilities have been partially decided in a manner adverse to those
utilities' positions.
On January 11, 1999, the ACC issued an order which stayed the amended rules,
granted reconsideration of the decision to make the rules permanent, and
directed the hearing division of the ACC to establish a procedural order for
further action on these rules. The order also granted waivers from compliance
with the rules for us, and all affected utilities.
On February 5, 1999, the ACC Hearing Division issued recommendations for changes
to the amended rules. The recommended changes to the amended rules were further
modified by a Procedural Order of the ACC Hearing Division dated March 12, 1999.
On April 14, 1999, the ACC voted to notice, for further rulemaking, the Hearing
Division's recommended changes, with certain exceptions. The proposed rules
approved by the ACC for further rulemaking include the following major
provisions:
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* They would 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.
* 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. Customers with single premise loads of
40 kilowatts or greater may aggregate loads to meet this one megawatt
requirement.
* When effective, residential customers will be phased in at 1 1/4% 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 with separate pricing for electric
services provided for noncompetitive services.
* ACC shall allow a reasonable opportunity for recovery of unmitigated
stranded costs (see "Stranded Costs" below).
* Absent an ACC waiver, prior to January 1, 2001, each affected utility must
transfer all competitive generation assets and services either to an
unaffiliated party or to a separate corporate affiliate.
The proposed rules approved on April 14, 1999 will not become final and
effective until approved by the ACC following formal rulemaking proceedings
under Arizona law. In compliance with statutory procedural requirements, ACC
oral proceedings on the matter are scheduled for June 14 and June 17, 1999.
We cannot currently predict when or if the amended rules will be further
modified, when the stay of the amended rules will be lifted, or when retail
electric competition will be introduced in Arizona.
STRANDED COSTS On June 22, 1998, the ACC issued an Order on stranded cost
determination and recovery. We believe that certain provisions of the stranded
cost order are deficient and in August 1998, we filed two lawsuits to protect
our legal rights relating to the order.
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On February 5, 1999, the ACC Hearing Division issued recommended changes to the
June 1998 stranded cost order. These recommended changes were further amended by
an ACC Procedural Order dated March 12, 1999. On April 14, 1999, the ACC voted
to adopt the Hearing Division's changes to the June 1998 stranded cost order.
The amended stranded cost order became effective on April 27, 1999 and allows us
and each affected utility to choose from any one of five options for the
recovery of stranded costs:
* Net Revenues Lost Methodology is the difference between generation revenues
under traditional regulation and generation revenues under competition.
This option provides for declining recovery percentages for stranded costs
over a five-year recovery period. Regulatory assets are to be fully
recovered under their presently authorized amortization schedule. In
accordance with a 1996 regulatory agreement, the ACC accelerated the
amortization of substantially all of our regulatory assets to an eight-year
period that ends June 30, 2004.
* Divestiture/Auction Methodology allows a utility to divest all or
substantially all of its generating assets, including regulatory assets
associated with generation, in order to collect 100 percent of the
difference between net sales price and book value of generating assets
divested over a ten-year period, with no return on the unamortized balance.
* Financial Integrity Methodology allows a utility "sufficient revenues to
meet minimum financial ratios" for a period of ten years.
* Settlement Methodology allows a settlement to be agreed upon by the ACC and
a utility.
* Any combination of the above if shown to be in the best interests of all
affected parties.
LEGISLATIVE INITIATIVES An Arizona joint legislative committee studied
electric utility industry restructuring issues in 1996 and 1997. In conjunction
with that study, the Arizona legislative counsel prepared memoranda in late 1997
related to the legal authority of the ACC to deregulate the Arizona electric
utility industry. The memoranda raise a question as to the degree to which the
ACC may, under the Arizona Constitution, deregulate any portion of the electric
utility industry and allow rates to be determined by market forces. This latter
issue has been subsequently decided by lower courts in favor of the ACC in four
separate lawsuits, two of which are unrelated.
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
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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.
In addition, the Arizona legislature will review and make recommendations for
the 1999 legislative session on certain competitive issues.
GENERAL We believe that further ACC decisions, legislation at the Arizona
and federal levels, and perhaps amendments to the Arizona Constitution (which
would require a vote of the people) will ultimately be required before
significant implementation of retail electric competition can lawfully occur in
Arizona. Until the manner of implementation of competition, including addressing
stranded costs, is determined, 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 reform bills have been introduced during recent
congressional sessions, which as currently written would allow consumers to
choose their electricity suppliers by 2000 or 2003. These bills, 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
substantial restructuring of the electric utility industry can occur.
REGULATORY ACCOUNTING
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
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the impact of regulatory decisions in its financial statements. Our existing
regulatory orders and the current regulatory environment support our accounting
practices related to regulatory assets, which amounted to about $900 million at
March 31, 1999. 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 will end June 30, 2004.
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.
Although rules have been proposed for transitioning generation services to
competition, there are many unresolved issues. We continue to apply SFAS No. 71
to our generation operations. If rate recovery of regulatory assets is no longer
probable, whether due to competition or regulatory action, we would be required
to write off the remaining balance as an extraordinary charge to expense.
6. 1996 Regulatory Agreement
In April 1996, the ACC approved a regulatory agreement between the ACC Staff and
us. The major provisions of this agreement are:
* An annual rate reduction of approximately $48.5 million ($29 million after
income taxes), or 3.4% on average for all customers except certain contract
customers, effective July 1, 1996.
* Recovery of substantially all of our present regulatory assets through
accelerated amortization over an eight-year period that will end June 30,
2004, increasing annual amortization by approximately $120 million ($72
million after income taxes).
* A formula for sharing future cost savings between customers and
shareholders (price reduction formula), referencing a return on equity (as
defined) of 11.25%.
* A moratorium on filing for permanent rate changes prior to July 2, 1999,
except under the price reduction formula and under certain other limited
circumstances.
* Infusion of $200 million of common equity by Pinnacle West, in annual
payments of $50 million starting in 1996.
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Based on the price reduction formula, the ACC approved retail price decreases of
approximately $17.6 million ($10.5 million after income taxes), or 1.2%,
effective July 1, 1997, and approximately $17 million ($10 million after income
taxes), or 1.1%, effective July 1, 1998. We expect to file with the ACC for
another retail price decrease of approximately $10.8 million annually ($6.5
million after income taxes) to become effective July 1, 1999. The amount and
timing of the price decrease are subject to ACC approval. This will be the last
price decrease under the 1996 regulatory agreement.
7. Agreement with Salt River Project
On April 25, 1998, we entered into a Memorandum of Agreement with Salt
River Project in anticipation of, and to facilitate, the opening of the Arizona
electric industry. The Agreement contains the following major components:
* Both parties would amend the Territorial Agreement to remove any barriers
to the provision of competitive electricity supply and non-distribution
services.
* Both parties would amend the Power Coordination Agreement to lower the
price that we will pay Salt River Project for purchased power by
approximately $17 million (pretax) during the first full year that the
Agreement is effective and by lesser annual amounts during the next seven
years.
* Both parties agreed on certain legislative positions regarding electric
utility restructuring at the state and federal level.
Certain provisions of the Agreement (including those relating to the amendments
of the Territorial Agreement and the Power Coordination Agreement) are affected
by the timing of the introduction of competition. See Note 5. On February 18,
1999, the ACC approved the Agreement.
8. 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
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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.
9. In the first quarter of 1999 we adopted EITF 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities." EITF 98-10 requires
energy trading contracts to be measured at fair value as of the balance sheet
date with the gains and losses included in earnings and separately disclosed in
the financial statements or footnotes. The effects of adopting EITF 98-10 were
not material to our financial statements.
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 2000. 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 and electric
industry restructuring
* the effects of regulatory agreements on our results
* our capital needs and resources and
* Year 2000 technology issues.
We suggest this section be read along with the 1998 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, 1999 and 1998:
Periods ended March 31
(Unaudited)
(Thousands of Dollars)
Three Months Twelve Months
------------------- -----------------------
1999 1998 1999 1998
-------- -------- ---------- ----------
Operating Revenues $413,983 $380,423 $2,039,958 $1,879,955
Earnings for Common Stock $ 32,779 $ 29,057 $ 249,266 $ 242,728
OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 1999 COMPARED WITH
THREE-MONTH PERIOD ENDED MARCH 31, 1998
Earnings increased $3.7 million in the three-month comparison primarily
because of an increase in customers and increased contributions from power
marketing and trading activities, partially offset by milder weather, a retail
price reduction, and higher depreciation and amortization expense. See Note 6
for information on the price reduction.
<PAGE>
-15-
Operating revenues increased $34 million because of:
* increased power marketing and trading revenues ($34 million)
* increases in the number of customers ($12 million) and
* miscellaneous factors ($3 million).
As mentioned above, these positive factors were partially offset by the
effects of milder weather ($11 million) and reductions in retail prices ($4
million).
Power marketing and trading activities are predominantly short-term
opportunity wholesale sales. The increase in power marketing revenues resulted
from increased activity in Western bulk power markets. The increase in power
marketing and trading revenues was accompanied by related increases in purchased
power expenses.
Depreciation and amortization expense increased $4 million because we had
more plant in service.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 1999 COMPARED WITH
TWELVE-MONTH PERIOD ENDED MARCH 31, 1998
Earnings increased $6.5 million in the twelve-month comparison primarily
because of an increase in customers, increased contributions from power
marketing and trading activities, and lower financing costs. In the comparison,
these positive factors more than offset the effects of milder weather, two
fuel-related settlements recorded in the third quarter of 1997, retail price
reductions that became effective July 1, 1997 and 1998, and higher depreciation
and amortization expense. See Note 6 for additional information about the price
reductions.
Operating revenues increased $160 million primarily because of:
* increased power marketing and trading revenues ($138 million)
* increases in the number of customers and the average amount of electricity
used by customers ($80 million) and
* miscellaneous factors ($7 million).
As mentioned above, these positive factors were partially offset by the
effects of milder weather ($47 million) and reductions in retail prices ($18
million).
Power marketing and trading activities are predominantly short-term
opportunity wholesale sales. The increase in power marketing revenues resulted
from increased activity in Western bulk power markets, higher prices, and
increased sales to large customers in California. The increase in power
marketing and trading revenues was accompanied by related increases in purchased
power expenses.
<PAGE>
-16-
The two fuel-related settlements increased pretax earnings in the twelve
months ended March 31, 1998 by approximately $21 million. The income statement
reflects these settlements as reductions in fuel expense and as other income.
Depreciation and amortization expense increased $15 million because we had
more plant in service.
Financing costs decreased by $9 million primarily because of lower amounts
of outstanding debt and preferred stock and lower interest rates.
OTHER INCOME
As part of a 1994 rate settlement with the ACC, we accelerated amortization
of substantially all deferred ITCs over a five-year period that ends on December
31, 1999. The amortization of ITCs is shown on our income statement as Other
Income -- Income Taxes. It decreases annual income tax expense by approximately
$28 million. Beginning in 2000, no further benefits will be reflected in income
tax expense.
LIQUIDITY AND CAPITAL RESOURCES
For the three months ended March 31, 1999, we incurred approximately $68
million in capital expenditures, which is approximately 21% of the most recently
estimated 1999 capital expenditures. Our projected capital expenditures for the
next three years are: 1999, $328 million; 2000, $317 million; and 2001, $300
million. These amounts include about $30 - $35 million each year for nuclear
fuel expenditures.
Our long-term debt and preferred stock redemption requirements and payment
obligations on a capitalized lease for the next three years are: 1999, $285
million; 2000, $115 million; and 2001, $2 million. During the three months ended
March 31, 1999, we redeemed approximately $10 million of our long-term debt and
all $96 million (including premiums) of our preferred stock with cash from
operations and long-term and short-term debt. In February 1999 we issued $125
million of unsecured long-term debt. As a result of the 1996 regulatory
agreement (see Note 6), Pinnacle West invested $50 million in the Company in
1996, 1997 and 1998 and will invest a similar amount in 1999.
Although provisions in our first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds that we may issue, we do not expect any of these provisions
to limit our ability to meet our capital requirements.
<PAGE>
-17-
YEAR 2000 READINESS DISCLOSURE
OVERVIEW As the year 2000 approaches, many companies face problems because many
computer systems and equipment will not properly recognize calendar dates
beginning with the year 2000. We are addressing the Year 2000 issue as described
below. We initiated a comprehensive company-wide Year 2000 program during 1997
to review and resolve all Year 2000 issues in mission critical systems (systems
and equipment that are key to the power production and delivery function,
health, and safety) in a timely manner to ensure the reliability of electric
service to our customers. This included a company-wide awareness program of the
Year 2000 issue. We have an internal audit/quality review team that is
periodically reviewing the individual Year 2000 projects and their Year 2000
readiness.
The following chart shows Year 2000 readiness of our mission critical systems as
of April 30, 1999:
INVENTORY ASSESSMENT REMEDIATION & TESTING
--------- ---------- ---------------------
100% 100% 90%*
* Estimated to be at 100% by June 30, 1999, except as discussed below.
DISCUSSION We have been actively implementing and replacing systems and
technology since 1995 for general business reasons unrelated to the Year 2000,
and these actions have resulted in substantially all of our major information
technology (IT) systems becoming Year 2000 ready. The major IT systems that
were, and are being, implemented and replaced include the following:
* Work Management
* Materials Management
* Energy Management System
* Payroll
* Financial
* Human Resources
* Trouble Call Management System
* Computer and Communications Network Upgrades
* Geographic Information System
* Customer Information System and
* Palo Verde Site Work Management System.
We have made, and will continue to make, certain modifications to computer
hardware and software systems and applications, including IT and non-IT systems,
in an effort to ensure they are capable of handling changing business needs,
including dates in the year 2000 and thereafter. In addition, we are analyzing
other IT systems and non-IT
<PAGE>
-18-
systems, including embedded technology and real-time process control systems,
for potential modifications.
We have inventoried and assessed essentially all mission critical IT and non-IT
systems and equipment. We are 90% complete with the remediation and testing of
these systems. Remediation and testing is expected to be completed by June 30,
1999, for all mission critical systems, except for (i) those items that can only
be completed during maintenance outages at Palo Verde, which will be completed
for the last unit, which is substantially identical to the other two units,
during the last half of 1999, and (ii) the continuous emissions monitoring
systems for our five fossil plants, which will also be completed during the last
half of 1999.
We currently estimate that we will spend about $5 million relating to Year 2000
issues, about $3 million of which has been spent to date. This includes an
estimated allocation of payroll costs for our employees working on Year 2000
issues, and costs for consultants, hardware, and software. We do not separately
track other internal costs. This does not include costs incurred since 1995 to
implement and replace systems for reasons unrelated to the Year 2000, as
discussed above. Our cost to address the Year 2000 issue is charged to operating
expenses as incurred and has not had, and is not expected to have, a material
adverse effect on our financial position, cash flows, or results of operations.
We expect to fund this cost with available cash balances and cash provided by
operations.
We are communicating with our significant suppliers, business partners, other
utilities, and large customers to determine the extent to which we may be
affected by these third parties' plans to remediate their own Year 2000 issues
in a timely manner. We have been interfacing with suppliers of systems,
services, and materials in order to assess whether their schedules for analysis
and remediation of Year 2000 issues are timely and to assess their ability to
continue to supply required services and materials.
We are also working with the North American Electric Reliability Council (NERC)
through the Western Systems Coordinating Council (WSCC) to develop operational
plans for stable grid operation that will be used by other utilities and us in
the western United States. Our operational plans are complete. However, we
cannot currently predict the effect on us if the systems of these other
companies are not Year 2000 ready.
We currently expect that our most reasonably likely worst case Year 2000
scenario would be intermittent loss of power to customers, similar to an outage
during a severe weather disturbance. In this situation, we would restore power
as soon as possible by, among other things, re-routing power flows. We do not
currently expect that this scenario would have a material adverse effect on our
financial position, cash flows, or results of operations.
<PAGE>
-19-
We are working to develop our own contingency plans to handle Year 2000 issues,
including the most reasonably likely worst case scenario, discussed above, and
we expect these plans to be completed by June 30, 1999. As discussed above, we
have also been working with NERC and WSCC to develop contingency plans related
to grid operation.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 for discussions of competitive developments and regulatory
accounting. See Note 7 for a discussion of a proposed amendment to a Power
Coordination Agreement with Salt River Project that we estimate would reduce our
pretax costs for purchased power by approximately $17 million during the first
full year that the amendment is effective and by lesser annual amounts during
the next seven years.
RATE MATTERS
See Note 6 for a discussion of a proposed price reduction that would be
effective July 1, 1999.
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 our traditional
regulated markets; regional economic conditions, which could affect customer
growth; the cost of debt and equity capital; weather variations affecting
customer usage; technological developments in the electric industry; the
successful completion of a large-scale construction project; and Year 2000
issues.
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
<PAGE>
-20-
decommissioning trust fund. Our policy is to manage interest rates through the
use of a combination of fixed 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 rates.
We utilize a variety of derivative instruments including exchange-traded
futures, options, and swaps as part of our overall risk management strategies
and for trading purposes. In order to reduce the risk of adverse price
fluctuations in the electricity and natural gas markets, we enter into futures
and/or option transactions to hedge certain natural gas held in storage as well
as certain expected purchases and sales of natural gas and electricity.
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 viability of counterparties.
Our exposure to market risks has not changed materially from December 31, 1998
to March 31,1999.
<PAGE>
-21-
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 the Company's construction and financing programs.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of
this report for a discussion of competition and the rules regarding the
introduction of retail electric competition in Arizona.
SPENT NUCLEAR FUEL AND WASTE DISPOSAL
As previously reported, on July 24, 1998, we filed a Petition for Review
regarding DOE's obligation to begin accepting spent nuclear fuel. See
"Generating Fuel and Purchased Power - Nuclear Fuel Supply - Spent Nuclear Fuel
and Waste Disposal" in Part I, Item 1 of the 1998 10-K. On April 16, 1999, the
court dismissed our petition, holding that we are bound by the court's previous
ruling in another case. That court held that DOE has an obligation to accept
spent nuclear fuel as of January 31, 1998, but did not order DOE to do so.
Instead, the court held that we must follow the provisions of our standard
contract for relief.
ENVIRONMENTAL MATTERS
PURPORTED NAVAJO ENVIRONMENTAL REGULATION As previously reported, on
February 19, 1999, the EPA promulgated regulations setting forth the EPA's
approach to issuing Federal permits to covered stationary sources on Indian
reservations, pursuant to the Clean Air Act Amendments of 1990. See
"Environmental Matters - Purported Navajo Environmental Regulation" in Part I,
Item 1 of our 1998 10-K. On April 15, 1999, we filed a Petition for Review in
the United States Court of Appeals for the District of Columbia. ARIZONA PUBLIC
SERVICE COMPANY V. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, No. 99-1146.
EPA ENVIRONMENTAL REGULATION On April 22, 1999, the EPA announced final
regional haze rules. See "Environmental Matters - EPA Environmental Regulation -
Clean Air Act" in our 1998 10-K. These new regulations require states to submit,
by 2008, implementation plans containing requirements to eliminate all man-made
emissions causing visibility impairment in certain specified areas, including
the Golden Circle of National Parks in the Colorado Plateau. The 2008
implementation plans must also include consideration and potential application
of best available retrofit technology
<PAGE>
-22-
("BART") for major stationary sources which came into operation between August
1962 and August 1977, such as the Navajo Generating Station, Cholla Power Plant
and Four Corners Power Plant.
The nine western states and tribes that participated in the Grand Canyon
Visibility Transport Commission process will have the option to follow an
alternate implementation plan and schedule for areas considered by the
Commission. Under this option, those states and tribes would submit
implementation plans by 2003, which would incorporate the emission reduction
scheme adopted in the Commission's recommendations. Any states and tribes that
implement this option will also have to submit revised implementation plans in
2008 to address visibility in certain specified areas that were not considered
by the Commission.
Because Arizona has the discretion to choose between the national or
Commission options and a variety of pollution controls to meet the requirements
of the regional haze rules, the actual impact on us cannot be determined at this
time.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
27.1 Financial Data Schedule
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:
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
</TABLE>
- --------
(a) Reports filed under File No. 1-4473 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
<PAGE>
-23-
(b) Reports on Form 8-K
During the quarter ended March 31, 1999, and the period from April 1
through May 17, 1999, the Company filed the following reports on Form 8-K:
Report dated January 11, 1999 relating to (i) the ACC hearing officers'
recommended changes to the amended rules regarding the introduction of retail
electric competition in Arizona and to the June 1998 stranded cost order and
(ii) action by the Arizona Supreme Court vacating its order staying ACC hearings
on the proposed settlement agreement and dismissing the Attorney General's
action.
Report dated February 18, 1999 comprised of Exhibits to the Company's
Registration Statements (Registration Nos. 333-27551 and 333-58445) relating to
the Company's offering of $125 million of Notes.
<PAGE>
-24-
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 17, 1999 By: George A. Schreiber, Jr.
--------------------------
George A. Schreiber, Jr.
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer
and Officer Duly Authorized to
sign this Report)
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