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 1-8962
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PINNACLE WEST CAPITAL CORPORATION
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(Exact name of registrant as specified in its charter)
Arizona 86-0512431
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 E. Van Buren St., P.O. Box 52132, Phoenix, Arizona 85072-2132
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (602) 379-2500
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- --------------------------------------------------------------------------------
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
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, no par value,
outstanding as of May 13, 1999: 84,822,997
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Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
APS - Arizona Public Service Company
APS Energy Services - APS Energy Services Company, Inc.
Company - Pinnacle West Capital Corporation
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"
El Dorado - El Dorado Investment Company
FERC - Federal Energy Regulatory Commission
ITC - Investment tax credit
MW - Megawatt, one million watts
1998 10-K - Pinnacle West Capital Corporation 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 APS 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. 128 - Statement of Financial Accounting Standards No. 128, "Earnings
Per Share"
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
SunCor - SunCor Development Company
Territorial Agreement - 1955 agreement between APS 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.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Dollars in thousands, except per share amounts)
Three Months Ended
March 31,
1999 1998
------------ ------------
Operating Revenues
Electric $ 414,154 $ 380,423
Real estate 24,533 34,161
------------ ------------
Total 438,687 414,584
------------ ------------
Operating Expenses
Fuel and purchased power 99,241 73,917
Utility operations and maintenance 99,084 96,416
Real estate operations 22,235 30,236
Depreciation and amortization 96,910 92,830
Taxes other than income taxes 29,447 30,348
------------ ------------
Total 346,917 323,747
------------ ------------
Operating Income 91,770 90,837
------------ ------------
Other Income (Expense)
Preferred stock dividend requirements of APS (1,016) (2,878)
Net other income and expense (2,508) 4,359
------------ ------------
Total (3,524) 1,481
------------ ------------
Income Before Interest and Income Taxes 88,246 92,318
------------ ------------
Interest Expense
Interest charges 40,769 42,922
Capitalized interest (4,074) (4,656)
------------ ------------
Total 36,695 38,266
------------ ------------
Income Before Income Tax 51,551 54,052
Income Taxes 20,861 22,966
------------ ------------
Net Income $ 30,690 $ 31,086
============ ============
Average Common Shares Outstanding - Basic 84,669,800 84,785,309
Average Common Shares Outstanding - Diluted 85,176,298 85,332,159
Earnings Per Average Common Share Outstanding:
Net income - basic $ 0.36 $ 0.37
Net income - diluted $ 0.36 $ 0.36
Dividends Declared Per Share $ 0.325 $ 0.300
============ ============
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Dollars in thousands, except per share amounts)
Twelve Months Ended
March 31,
1999 1998
----------- -----------
Operating Revenues
Electric $ 2,040,129 $ 1,879,955
Real estate 114,560 131,091
----------- -----------
Total 2,154,689 2,011,046
----------- -----------
Operating Expenses
Fuel and purchased power 562,825 425,075
Utility operations and maintenance 416,709 407,834
Real estate operations 107,330 122,102
Depreciation and amortization 383,759 368,513
Taxes other than income taxes 116,005 121,650
----------- -----------
Total 1,586,628 1,445,174
----------- -----------
Operating Income 568,061 565,872
----------- -----------
Other Income (Expense)
Preferred stock dividend requirements of APS (7,841) (12,055)
Net other income and expense (6,258) 4,705
----------- -----------
Total (14,099) (7,350)
----------- -----------
Income Before Interest and Income Taxes 553,962 558,522
----------- -----------
Interest Expense
Interest charges 166,992 180,971
Capitalized interest (18,014) (19,688)
----------- -----------
Total 148,978 161,283
----------- -----------
Income Before Income Taxes 404,984 397,239
Income Taxes 162,488 155,679
----------- -----------
Net Income $ 242,496 $ 241,560
=========== ===========
Average Common Shares Outstanding - Basic 84,745,736 84,853,589
Average Common Shares Outstanding - Diluted 85,351,957 85,383,767
Earnings Per Average Common Share Outstanding:
Net income - basic $ 2.86 $ 2.85
Net income - diluted $ 2.84 $ 2.83
Dividends Declared Per Share $ 1.250 $ 1.150
=========== ===========
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
(Thousands of Dollars)
March 31, December 31,
1999 1998
---------- ------------
Current Assets
Cash and cash equivalents $ 25,709 $ 20,538
Customer and other receivables--net 198,608 233,876
Accrued utility revenues 58,936 67,740
Materials and supplies 71,232 69,074
Fossil fuel 13,009 13,978
Deferred income taxes 4,052 3,999
Other current assets 54,601 47,594
---------- ----------
Total current assets 426,147 456,799
---------- ----------
Investments and Other Assets
Real estate investments--net 332,454 331,021
Other assets 255,285 236,562
---------- ----------
Total investments and other assets 587,739 567,583
---------- ----------
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
---------- ----------
Net utility plant 4,713,202 4,730,563
---------- ----------
Deferred Debits
Regulatory asset for income taxes 387,616 400,795
Rate synchronization cost deferral 289,857 303,660
Other deferred debits 367,397 365,146
---------- ----------
Total deferred debits 1,044,870 1,069,601
---------- ----------
Total Assets $6,771,958 $6,824,546
========== ==========
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
LIABILITIES AND EQUITY
(Thousands of Dollars)
March 31, December 31,
1999 1998
---------- ------------
Current Liabilities
Accounts payable $ 104,628 $ 155,800
Accrued taxes 117,235 62,520
Accrued interest 27,957 31,866
Short-term borrowings 112,725 178,830
Current maturities of long-term debt 157,646 168,045
Customer deposits 28,348 28,510
Other current liabilities 23,013 14,632
---------- ----------
Total current liabilities 571,552 640,203
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Long-Term Debt Less Current Maturities 2,170,640 2,048,961
---------- ----------
Deferred Credits and Other
Deferred income taxes 1,334,840 1,343,536
Deferred investment tax credit 25,293 27,345
Unamortized gain - sale of utility plant 76,643 77,787
Other 431,076 428,122
---------- ----------
Total deferred credits and other 1,867,852 1,876,790
---------- ----------
Commitments and contingencies (Notes 5, 8, 9, and 11)
Minority Interests
Non-redeemable preferred stock of APS -- 85,840
---------- ----------
Redeemable preferred stock of APS -- 9,401
---------- ----------
Common Stock Equity
Common stock, no par value 1,546,055 1,550,643
Retained earnings 615,859 612,708
---------- ----------
Total common stock equity 2,161,914 2,163,351
---------- ----------
Total Liabilities and Equity $6,771,958 $6,824,546
========== ==========
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(THOUSANDS OF DOLLARS)
Three Months Ended
March 31,
1999 1998
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 30,690 $ 31,086
Items not requiring cash
Depreciation and amortization 96,910 92,830
Nuclear fuel amortization 8,269 8,417
Deferred income taxes--net (7,870) (11,419)
Deferred investment tax credit (2,052) (2,426)
Other--net 926 1,521
Changes in current assets and liabilities
Customer and other receivables--net 35,268 44,468
Accrued utility revenues 8,804 9,028
Materials, supplies and fossil fuel (1,189) (3,501)
Other current assets (7,007) (2,585)
Accounts payable (52,168) (37,749)
Accrued taxes 54,715 53,384
Accrued interest (3,909) (4,509)
Other current liabilities 8,969 10,679
Decrease (increase) in land held (1,256) 11,556
Other--net (191) 6,113
--------- ---------
Net Cash Flow Provided By Operating Activities 168,909 206,893
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (67,467) (60,848)
Capitalized interest (4,074) (4,656)
Other--net (9,082) 2,325
--------- ---------
Net Cash Flow Used For Investing Activities (80,623) (63,179)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 127,928 99,375
Short-term borrowings--net (66,105) (49,750)
Dividends paid on common stock (27,534) (25,436)
Repayment of long-term debt (17,575) (162,216)
Redemption of preferred stock (96,499) (10,599)
Other--net (3,330) (453)
--------- ---------
Net Cash Flow Used For Financing Activities (83,115) (149,079)
--------- ---------
Net Cash Flow 5,171 (5,365)
Cash and Cash Equivalents at Beginning of Period 20,538 27,484
--------- ---------
Cash and Cash Equivalents at End of Period $ 25,709 $ 22,119
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 37,434 $ 40,942
Income taxes $ -- $ 4,600
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. The condensed consolidated financial statements include the accounts of
Pinnacle West and its subsidiaries: APS, SunCor, El Dorado and APS Energy
Services. All significant intercompany balances have been eliminated. We have
reclassified certain prior year amounts to conform to the current year
presentation.
2. Our unaudited condensed consolidated 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
consolidated financial statements and notes to condensed consolidated financial
statements be read along with the consolidated financial statements and notes to
consolidated financial statements included in our 1998 10-K.
3. Weather conditions can have a significant impact on APS' results for interim
periods. For this and other reasons, results for interim periods do not
necessarily represent results to be expected for the year.
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 APS. We believe that
certain provisions of the 1996 ACC rules and the amended rules are deficient and
APS has filed lawsuits to protect its 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 APS, 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
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recommended changes, with certain exceptions. The proposed rules approved by the
ACC for further rulemaking consideration include the following major provisions:
* They would apply to virtually all Arizona electric utilities regulated by
the ACC, including APS.
* The rules require each affected utility, including APS, 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. APS believes that certain provisions of the stranded
cost order
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are deficient and in August 1998, APS filed two lawsuits to protect its legal
rights relating to the order.
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
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 APS' 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 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
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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. APS does
not expect these rules to have a material impact on its 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
APS prepares its 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. APS'
existing regulatory orders and the current regulatory environment support its
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 APS' 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. APS continues to apply SFAS No.
71 to its
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generation operations. If rate recovery of regulatory assets is no longer
probable, whether due to competition or regulatory action, APS 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
APS. 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 APS' 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 into APS by the parent company,
in annual payments of $50 million starting in 1996.
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. APS expects 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.
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7. Agreement with Salt River Project
On April 25, 1998, APS 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 APS 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, APS
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 APS'
29.1% interest in the three Palo Verde units, APS' 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. APS has 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.
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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.
10. SFAS No. 128, "Earnings Per Share" requires the presentation of both basic
and diluted earnings per share on the consolidated financial statements.
Dilutive stock options increased average common shares outstanding by 506,498
and 546,850 for the three-month period ended March 31, 1999 and 1998,
respectively; and 606,221 and 530,178 for the twelve-month period ended March
31, 1999 and 1998, respectively, but had no effect on net income. Total average
common shares outstanding for the purposes of calculating diluted earnings per
share were 85,176,298 and 85,332,159 for the three-month period ended March 31,
1999 and 1998, respectively; and 85,351,957 and 85,383,767 for the twelve-month
period ended March 31, 1999 and 1998, respectively.
11. On April 23, 1999, we entered into a memorandum of understanding with
Calpine Corporation, an independent power producer located in San Jose,
California, for a potential $220 million, 500 MW expansion at the site of APS'
West Phoenix Power Plant. The joint project is the second phase of a potential
750 MW expansion at West Phoenix. The first phase includes a $60 million
repowering of an existing unit to create a 130 MW combined cycle unit. The
remainder of the expansion involves repowering other existing units at the West
Phoenix site. Assuming approvals are granted, construction is scheduled to begin
in mid-2000, with commercial operation of the first phase in mid-2001 and of the
second phase in late 2001.
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PINNACLE WEST CAPITAL CORPORATION
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 for Pinnacle West and our subsidiaries: APS, SunCor, El
Dorado, and APS Energy Services, 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 Consolidated
Financial Statements. These Notes add further details to the discussion.
OPERATING RESULTS
OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 1999 COMPARED WITH
THREE-MONTH PERIOD ENDED MARCH 31, 1998
Consolidated net income for the three months ended March 31, 1999 was $30.7
million compared with $31.1 million for the same period in the prior year. Net
income decreased slightly in the three-month comparison because higher earnings
at APS and lower financing costs at the parent company were more than offset by
lower earnings at the other subsidiaries.
APS earnings for the first quarter of 1999 were $32.8 million compared with
$29.1 million for the same period in the prior year. APS earnings increased 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.
Electric 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).
<PAGE>
-15-
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 APS had more
plant in service.
Parent company financing costs decreased $2 million because we paid down debt.
SunCor's earnings decreased $2 million in the three-month period primarily
because of a decrease in net land sales.
El Dorado's earnings decreased $3 million because of investment sales in 1998.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 1999 COMPARED WITH
TWELVE-MONTH PERIOD ENDED MARCH 31, 1998
Net income for the twelve months ended March 31, 1999 was $242.5 million
compared with $241.6 million for the same period in the prior year. Net income
increased slightly because of increased earnings at APS and lower financing
costs at the parent company, partially offset by lower contributions from other
subsidiaries.
APS earnings were $249.3 million for the twelve months ended March 31, 1999
compared with $242.7 million for the twelve months ended March 31, 1998. APS
earnings increased 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.
Electric operating revenues increased $160 million primarily because of:
* increased power marketing and trading revenues ($138 million)
* increases in the number of customers and the 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).
<PAGE>
-16-
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.
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 APS had more
plant in service.
APS decreased its financing costs by $9 million primarily because of lower
amounts of outstanding debt and preferred stock and lower interest rates.
Parent company financing costs decreased $9 million as we paid down debt and
took advantage of lower interest rates.
El Dorado's earnings decreased $7 million in the twelve-month period because of
investment sales in 1998 and 1997.
INVESTMENT TAX CREDIT AMORTIZATION
As part of a 1994 rate settlement with the ACC, APS accelerated
amortization of substantially all deferred ITCs over a five-year period that
ends on December 31, 1999. The amortization of ITCs decreases annual
consolidated income tax expense by approximately $24 million. Beginning in 2000,
no further benefits will be reflected in income tax expense.
LIQUIDITY AND CAPITAL RESOURCES
PARENT COMPANY
The parent company's cash requirements and its ability to fund those
requirements are discussed under "Capital Needs and Resources" in Management's
Discussion and Analysis of Financial Condition and Results of Operation in Part
II, Item 7 of the 1998 10-K.
During the three-months ended March 31, 1999, the parent company redeemed
approximately $7 million of its long-term debt with cash from operations and
short-term borrowings.
<PAGE>
-17-
As a result of the 1996 regulatory agreement (see Note 6), the parent
company has invested $50 million in APS in 1996, 1997, and 1998 and will invest
a similar amount in 1999.
On April 23, 1999, we entered into a memorandum of understanding with
Calpine Corporation, an independent power producer located in San Jose,
California, for a potential $220 million, 500 MW expansion at the site of APS'
West Phoenix Power Plant. The joint project is the second phase of a potential
750 MW expansion at West Phoenix. The first phase includes a $60 million
repowering of an existing unit to create a 130 MW combined cycle unit. The
remainder of the expansion involves repowering other existing units at the West
Phoenix site. Assuming approvals are granted, construction is scheduled to begin
in mid-2000, with commercial operation of the first phase in mid-2001 and of the
second phase in late 2001. We are also considering additional expansion over the
next several years, which may result in additional expenditures. We currently
believe that there will be additional opportunities to expand our investment in
generating assets in the next five years. It is expected that these and other
generating assets would be organized in a non-regulated subsidiary under the
parent company.
The Board declared a quarterly dividend of 32.5 cents per share of common
stock, payable June 1, 1999 to shareholders of record on May 3, 1999, totaling
approximately $27.6 million.
APS
For the three months ended March 31, 1999, APS incurred approximately $68
million in capital expenditures, which is approximately 21% of the most recently
estimated 1999 capital expenditures. APS' 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.
APS' 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, APS redeemed approximately $10 million of long-term debt and all
$96 million (including premiums) of its preferred stock with cash from
operations and long-term and short-term debt. In February 1999 APS 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 APS in 1996, 1997
and 1998 and will invest a similar amount in 1999.
Although provisions in APS' first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds that APS may issue, APS does not expect any of these
provisions to limit its ability to meet its capital requirements.
<PAGE>
-18-
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. APS 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. APS has 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
--------- ---------- ---------------------
APS 100% 100% 90%(1)
- --- --- --- ---
Pinnacle West and
other subsidiaries
(excluding APS) 100% 100% 85%(2)
(1) Estimated to be at 100% by June 30, 1999, except as discussed below.
(2) Estimated to be at 100% by September 30, 1999.
DISCUSSION APS has 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 its 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.
<PAGE>
-19-
We and our subsidiaries 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, other APS IT systems and non-IT systems, including
embedded technology and real-time process control systems, are being analyzed
for potential modifications.
Pinnacle West and its subsidiaries have inventoried and assessed
essentially all mission critical IT and non-IT systems and equipment. APS is 90%
complete and Pinnacle West and its other subsidiaries are 85% 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 APS' five fossil plants, which will also be
completed during the last half of 1999.
APS currently estimates that it will spend approximately $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 APS 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 any
expenditures 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.
Pinnacle West and its subsidiaries are communicating with their significant
suppliers, business partners, other utilities, and large customers to determine
the extent to which they may be affected by these third parties' plans to
remediate their own Year 2000 issues in a timely manner. These companies 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.
APS is 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 utilized by APS and
other utilities in the western United States. APS' operational plans are
complete. However, APS cannot currently predict the effect on APS if the systems
of these other companies are not Year 2000 ready.
<PAGE>
-20-
We currently expect that our most reasonably likely worst case Year 2000
scenario would be intermittent loss of power to APS customers, similar to an
outage during a severe weather disturbance. In this situation, APS 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.
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, APS has 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 APS estimates would reduce
its 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; the ability of APS to successfully compete outside its 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; Year 2000
issues; the successful completion of a large-scale construction project; and the
strength of the real estate market.
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.
<PAGE>
-21-
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 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.
APS utilizes a variety of derivative instruments including exchange-traded
futures, options, and swaps as part of its 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, APS enters 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.
APS is exposed to credit losses in the event of non-performance or non-payment
by counterparties. APS uses a credit management process to assess and monitor
the financial viability of counterparties.
Our exposure to market risks, including those of APS, has not changed materially
from December 31, 1998 to March 31, 1999.
<PAGE>
-22-
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 APS' construction and financing programs.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 of Notes to Condensed Consolidated 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, APS 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 APS' petition, holding that APS is 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 APS must follow the provisions of its 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, APS 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 ("BART") for major stationary sources
which came into operation between August 1962
<PAGE>
-23-
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 APS 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>
10.1 Articles of Incorporation 19.1 to the Company's 1-8962 11-14-88
restated as of July 29, 1988 September 30, 1988
Form 10-Q Report
10.2 Bylaws, amended as of 3.1 to the Company's 1995 1-8962 4-1-96
February 21, 1996 Form 10-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>
-24-
(b) Reports on Form 8-K
During the quarter ended March 31, 1999, and the period from April 1
through May 17, 1999, we 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.
<PAGE>
-25-
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.
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Dated: May 17, 1999 By: George A. Schreiber, Jr.
-----------------------------
George A. Schreiber, Jr.
President and
Chief Financial Officer
(Principal Financial Officer
and Officer Duly Authorized
to sign this Report)
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