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 September 30, 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
PINNACLE WEST CAPITAL CORPORATION
------------------------------------------------------
(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
- ------------------------------------------------------ ----------
(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 November 12, 1999: 84,738,386
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., a direct access
electricity provider
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 Application of FASB Statements
No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises -- Accounting for the Discontinuation of Application of
FASB Statement No. 71"
El Dorado - El Dorado Investment Company
EPA - Environmental Protection Agency
FASB - Financial Accounting Standards Board
FERC - Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
ITC - Investment tax credit
June 10-Q - Pinnacle West Capital Corporation Quarterly Report on Form 10-Q for
the fiscal quarter ended June 30, 1999
NGS - Navajo Generating Station
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
Pinnacle West Energy - Pinnacle West Energy 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
SunCor - SunCor Development Company
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.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Dollars in thousands, except per share amounts)
Three Months Ended
September 30,
----------------------------
1999 1998
------------ ------------
Operating Revenues
Electric $ 867,630 $ 740,734
Real estate 26,640 18,276
----------- -----------
Total 894,270 759,010
----------- -----------
Operating Expenses
Fuel and purchased power 396,614 252,699
Utility operations and maintenance 110,082 110,259
Real estate operations 26,757 18,821
Depreciation and amortization 95,068 94,981
Taxes other than income taxes 25,455 30,412
----------- -----------
Total 653,976 507,172
----------- -----------
Operating Income 240,294 251,838
----------- -----------
Other Income (Expense)
Preferred stock dividend requirements of APS -- (2,347)
Net other income and expense 1,040 (1,511)
----------- -----------
Total 1,040 (3,858)
----------- -----------
Income From Continuing Operations Before Interest
and Income Taxes 241,334 247,980
----------- -----------
Interest Expense
Interest charges 39,614 42,046
Capitalized interest (1,990) (4,731)
----------- -----------
Total 37,624 37,315
----------- -----------
Income From Continuing Operations Before Income Taxes 203,710 210,665
Income Taxes 78,131 83,384
----------- -----------
Income From Continuing Operations 125,579 127,281
Income Tax Benefit From Discontinued Operations 38,000 --
Extraordinary Charge - Net of Income Taxes of $94,115 (139,885) --
----------- -----------
Net Income $ 23,694 $ 127,281
=========== ===========
Average Common Shares Outstanding - Basic 84,758,516 84,769,615
Average Common Shares Outstanding - Diluted 84,988,902 85,326,808
Earnings Per Average Common Share Outstanding
Continuing Operations - Basic $ 1.48 $ 1.50
Net Income - Basic $ 0.28 $ 1.50
Continuing Operations - Diluted $ 1.48 $ 1.49
Net Income - Diluted $ 0.28 $ 1.49
Dividends Declared Per Share $ -- $ --
=========== ===========
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)
Nine Months Ended
September 30,
----------------------------
1999 1998
------------ ------------
Operating Revenues
Electric $ 1,793,047 $ 1,562,872
Real estate 83,870 81,353
------------ ------------
Total 1,876,917 1,644,225
------------ ------------
Operating Expenses
Fuel and purchased power 628,398 422,201
Utility operations and maintenance 315,400 309,388
Real estate operations 78,393 75,270
Depreciation and amortization 289,361 281,396
Taxes other than income taxes 84,504 90,690
------------ ------------
Total 1,396,056 1,178,945
------------ ------------
Operating Income 480,861 465,280
------------ ------------
Other Income (Expense)
Preferred stock dividend requirements of APS (1,016) (7,660)
Net other income and expense (898) 3,040
------------ ------------
Total (1,914) (4,620)
------------ ------------
Income From Continuing Operations Before Interest
and Income Taxes 478,947 460,660
------------ ------------
Interest Expense
Interest charges 121,488 127,409
Capitalized interest (10,253) (14,261)
------------ ------------
Total 111,235 113,148
------------ ------------
Income From Continuing Operations Before Income Taxes 367,712 347,512
Income Taxes 142,741 140,148
------------ ------------
Income From Continuing Operations 224,971 207,364
Income Tax Benefit From Discontinued Operations 38,000 --
Extraordinary Charge - Net of Income Taxes of $94,115 (139,885) --
------------ ------------
Net Income $ 123,086 $ 207,364
============ ============
Average Common Shares Outstanding - Basic 84,715,155 84,788,514
Average Common Shares Outstanding - Diluted 85,086,502 85,355,520
Earnings Per Average Common Share Outstanding
Continuing Operations - Basic $ 2.66 $ 2.45
Net Income - Basic $ 1.45 $ 2.45
Continuing Operations - Diluted $ 2.64 $ 2.43
Net Income - Diluted $ 1.45 $ 2.43
Dividends Declared Per Share $ 0.975 $ 0.900
============ ============
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
September 30,
----------------------------
1999 1998
------------ ------------
Operating Revenues
Electric $ 2,236,573 $ 1,970,832
Real estate 126,705 117,188
------------ ------------
Total 2,363,278 2,088,020
------------ ------------
Operating Expenses
Fuel and purchased power 743,698 515,519
Utility operations and maintenance 420,053 421,542
Real estate operations 118,454 109,348
Depreciation and amortization 387,644 373,676
Taxes other than income taxes 110,720 121,098
------------ ------------
Total 1,780,569 1,541,183
------------ ------------
Operating Income 582,709 546,837
------------ ------------
Other Income (Expense)
Preferred stock dividend requirements of APS (3,059) (10,658)
Net other income and expense (3,329) (3,374)
------------ ------------
Total (6,388) (14,032)
------------ ------------
Income From Continuing Operations Before Interest
and Income Taxes 576,321 532,805
------------ ------------
Interest Expense
Interest charges 163,224 172,087
Capitalized interest (14,588) (18,969)
------------ ------------
Total 148,636 153,118
------------ ------------
Income From Continuing Operations Before Income Taxes 427,685 379,687
Income Taxes 167,186 153,371
------------ ------------
Income From Continuing Operations 260,499 226,316
Income Tax Benefit From Discontinued Operations 38,000 --
Extraordinary Charge - Net of Income Taxes of $94,115 (139,885) --
------------ ------------
Net Income $ 158,614 $ 226,316
============ ============
Average Common Shares Outstanding - Basic 84,719,349 84,773,062
Average Common Shares Outstanding - Diluted 85,139,539 85,223,290
Earnings Per Average Common Share Outstanding
Continuing Operations - Basic $ 3.07 $ 2.67
Net Income - Basic $ 1.87 $ 2.67
Continuing Operations - Diluted $ 3.06 $ 2.66
Net Income - Diluted $ 1.86 $ 2.66
Dividends Declared Per Share $ 1.300 $ 1.200
============ ============
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Thousands of Dollars)
September 30, December 31,
1999 1998
(Unaudited)
---------- ----------
Current Assets
Cash and cash equivalents $ 24,026 $ 20,538
Customer and other receivables--net 340,691 233,876
Accrued utility revenues 101,283 67,740
Materials and supplies 69,897 69,074
Fossil fuel 17,913 13,978
Deferred income taxes 4,058 3,999
Other current assets 59,649 47,594
---------- ----------
Total current assets 617,517 456,799
---------- ----------
Investments and Other Assets
Real estate investments--net 335,619 331,021
Other assets 261,192 236,562
---------- ----------
Total investments and other assets 596,811 567,583
---------- ----------
Property, Plant and Equipment
Plant in service and held for future use 7,476,307 7,265,604
Less accumulated depreciation and
amortization 3,005,900 2,814,762
---------- ----------
Total 4,470,407 4,450,842
Construction work in progress 214,644 228,643
Nuclear fuel, net of amortization 53,560 51,078
---------- ----------
Net property, plant and equipment 4,738,611 4,730,563
---------- ----------
Deferred Debits
Regulatory assets 648,377 980,084
Other deferred debits 114,023 89,517
---------- ----------
Total deferred debits 762,400 1,069,601
---------- ----------
Total Assets $6,715,339 $6,824,546
========== ==========
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
(Thousands of Dollars)
September 30, December 31,
1999 1998
(Unaudited)
---------- ----------
Current Liabilities
Accounts payable $ 241,915 $ 155,800
Accrued taxes 192,891 62,520
Accrued interest 23,995 31,866
Short-term borrowings 223,500 178,830
Current maturities of long-term debt 117,810 168,045
Customer deposits 25,410 28,510
Other current liabilities 25,611 14,632
---------- ----------
Total current liabilities 851,132 640,203
---------- ----------
Long-Term Debt Less Current Maturities 1,977,100 2,048,961
---------- ----------
Deferred Credits and Other
Deferred income taxes 1,173,710 1,343,536
Deferred investment tax credit 6,926 27,345
Unamortized gain - sale of utility plant 74,355 77,787
Other 439,840 428,122
---------- ----------
Total deferred credits and other 1,694,831 1,876,790
---------- ----------
Commitments and contingencies (Notes 6, 8, 9 and 10)
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 1,539,135 1,550,643
Retained earnings 653,141 612,708
---------- ----------
Total common stock equity 2,192,276 2,163,351
---------- ----------
Total Liabilities and Equity $6,715,339 $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)
Nine Months Ended
September 30,
----------------------
1999 1998
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations $ 224,971 $ 207,364
Items not requiring cash
Depreciation and amortization 289,361 281,396
Nuclear fuel amortization 24,306 24,991
Deferred income taxes--net (74,670) (11,533)
Deferred investment tax credit (20,419) (20,285)
Other--net 1,511 1,045
Changes in current assets and liabilities
Customer and other receivables--net (106,815) (112,194)
Accrued utility revenues (33,543) (27,594)
Materials, supplies and fossil fuel (4,758) (8,944)
Other current assets (12,055) (5,648)
Accounts payable 81,805 60,062
Accrued taxes 130,371 121,269
Accrued interest (7,871) (4,902)
Other current liabilities 13,964 16,731
Decrease (increase) in land held (4,237) 16,388
Other--net 28,431 (23,451)
--------- ---------
Net Cash Flow Provided By Operating Activities 530,352 514,695
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (235,568) (221,904)
Capitalized interest (10,253) (14,261)
Sale of property -- 1,624
Other--net (5,567) (3,986)
--------- ---------
Net Cash Flow Used For Investing Activities (251,388) (238,527)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 249,191 112,575
Short-term borrowings--net 44,670 (15,400)
Dividends paid on common stock (82,652) (76,311)
Repayment of long-term debt (379,936) (254,782)
Redemption of preferred stock (96,499) (37,585)
Other--net (10,250) (2,023)
--------- ---------
Net Cash Flow Used For Financing Activities (275,476) (273,526)
--------- ---------
Net Cash Flow 3,488 2,642
Cash and Cash Equivalents at Beginning of Period 20,538 27,484
--------- ---------
Cash and Cash Equivalents at End of Period $ 24,026 $ 30,126
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 109,702 $ 112,348
Income taxes $ 95,590 $ 81,305
See Notes to Condensed Consolidated Financial Statements.
-8-
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, APS Energy Services,
and Pinnacle West Energy. 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 with exception of the extraordinary
item and the tax benefit from discontinued operations. 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 nine months ended September 30, 1999.
5. Regulatory Accounting
For the regulated operations, 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.
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.
In September 1999, the Settlement Agreement with the ACC was approved (see Note
6 for a discussion of the agreement), and, as a result, APS has discontinued the
application of SFAS No. 71 for its generation operations. This meant that
regulatory assets, unless reestablished as recoverable through ongoing regulated
cash flows, were eliminated and the generation assets were tested for
impairment. APS
-9-
determined that the generation assets were not impaired. A regulatory
disallowance, which removed $234 million pretax ($183 million net present value)
from ongoing regulatory cash flows, was recorded as a net reduction of
regulatory assets. This reduction ($140 million after income taxes or $1.65 per
basic share and $1.64 per diluted share) was reported as an extraordinary charge
on the income statement. The regulatory assets to be recovered under this
Settlement Agreement will be amortized as follows:
(Millions)
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
- ---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
The condensed consolidated balance sheets include the amounts listed below for
generation assets included in property, plant and equipment not subject to SFAS
No. 71:
(Thousands of Dollars)
September 30, December 31,
1999 1998
----------- -----------
Electric plant in service and held for future use $ 3,730,840 $ 3,680,482
Accumulated depreciation and amortization (1,793,288) (1,681,099)
Construction work in progress 85,638 107,324
Nuclear fuel, net of amortization 53,560 51,078
6. Regulatory Matters -- Electric Industry Restructuring
STATE
SETTLEMENT AGREEMENT As of May 14, 1999, APS entered into a comprehensive
Settlement Agreement with various other parties, including representatives of
major consumer groups, related to the implementation of retail electric
competition. On September 23, 1999, the ACC voted to approve the Settlement
Agreement, with some modifications.
The following are the major provisions of the Settlement Agreement, as approved:
* APS will reduce rates for standard offer service for customers with loads
less than 3 megawatts in a series of annual rate reductions of 1.5%
beginning July 1, 1999 through July 1, 2003, for a total of 7.5%. The first
reduction of approximately $24 million ($14 million after income taxes)
includes the July 1, 1999 retail price decrease of approximately $10.8
million annually ($6.5 million
-10-
after income taxes) related to the 1996 regulatory agreement. See "1996
Regulatory Agreement" below. For customers having loads 3 megawatts or
greater, standard offer rates will be reduced in annual increments that
total 5% through 2002.
* Unbundled rates being charged by APS for competitive direct access service
(for example, distribution services) became effective upon approval of the
Settlement Agreement, retroactive to July 1, 1999, and also will be subject
to annual reductions, that vary by rate class, through 2003.
* There will be a moratorium on retail rate changes for standard offer and
unbundled competitive direct access rates until July 1, 2004, except for
the price reductions described above and certain other limited
circumstances. Neither the ACC nor APS will be prevented from seeking or
authorizing rate changes prior to July 1, 2004 in the event of conditions
or circumstances that constitute an emergency, such as an inability to
finance on reasonable terms, or material changes in APS' cost of service
for ACC-regulated services resulting from federal, tribal, state or local
laws, regulatory requirements, judicial decisions, actions or orders.
* APS will be permitted to defer for later recovery prudent and reasonable
costs of complying with the ACC electric competition rules, system benefits
costs in excess of the levels included in current rates, and costs
associated with APS' "provider of last resort" and standard offer
obligations for service after July 1, 2004. These costs are to be recovered
through an adjustment clause or clauses commencing on July 1, 2004.
* APS' distribution system opened for retail access, effective September 24,
1999. Customers will be eligible for retail access in accordance with the
phase-in adopted by the ACC under the electric competition rules (see
"Retail Electric Competition Rules" below), with an additional 140
megawatts being made available to eligible non-residential customers.
Unless subject to judicial or regulatory restraint, APS will open its
distribution system to retail access for all customers on January 1, 2001.
* APS is currently recovering substantially all of its regulatory assets
through July 1, 2004, pursuant to the 1996 regulatory agreement. In
addition, the Settlement Agreement states that APS has demonstrated that
its allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value. APS will not be
allowed to recover $183 million net present value of the above amounts. The
Settlement Agreement provides that APS will have the opportunity to recover
$350 million net present value through a competitive transition charge
(CTC) that will remain in effect through December 31, 2004, at which time
it will terminate. Any over/under-recovery will be credited/debited
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against the costs subject to recovery under the adjustment clause described
above.
* APS will form a separate corporate affiliate or affiliates and transfer to
that affiliate(s) its generating assets and competitive services at book
value as of the date of transfer, which transfer shall take place by
December 31, 2002. APS will be allowed to defer and later collect
sixty-seven percent of its costs to accomplish the required transfer of
generation assets to an affiliate.
* When the Settlement Agreement approved by the ACC is no longer subject to
judicial review, APS will move to dismiss all of its litigation pending
against the ACC as of the date APS entered into the Settlement Agreement.
On October 25, 1999, two parties filed motions for reconsideration of the
Settlement Agreement with the ACC. The ACC took no action within the twenty day
limit, so the motions are deemed denied. APS continues to operate under the
terms of the Settlement Agreement.
In its motion for reconsideration, one of the parties has questioned 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.
The issue of competitively set rates has been decided by lower Arizona courts in
favor of the ACC in four separate lawsuits, two of which relate to
telecommunications companies. Appeals of the lower courts' decisions are
pending.
As discussed in Note 5 above, APS has discontinued the application of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation," for its generation operations.
RETAIL ELECTRIC COMPETITION RULES On September 21, 1999, the ACC voted to
approve the rules that provide a framework for the introduction of retail
electric competition in Arizona (the "Rules"). If any of the Rules conflict with
the Settlement Agreement, the terms of the Settlement Agreement govern. On
October 19, 1999, several parties, including APS, filed motions for
reconsideration of the Rules with the ACC. The ACC took no action within the
twenty day limit, so the motions are deemed denied.
The Rules approved by the ACC include the following major provisions:
* They 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
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and unbundled rates (Final Decision Date) or January 1, 2001, whichever is
earlier, and 100% beginning January 1, 2001. Under the Settlement
Agreement, APS will provide retail access to customers representing the
minimum 20% required by the ACC and an additional 140 megawatts of
non-residential load in 1999, and to all customers as of January 1, 2001,
or such other dates as approved by the ACC.
* Subject to the 20% requirement, all utility customers with single premise
loads of one megawatt or greater will be eligible for competitive electric
services on the Final Decision Date, which for the Company's customers was
the approval of the Settlement Agreement. Customers 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 non-competitive services.
* The ACC shall allow a reasonable opportunity for recovery of unmitigated
stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
generation assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the Settlement Agreement, APS received
a waiver to allow transfer of its competitive generation assets and
services to affiliates no later than December 31, 2002.
1996 REGULATORY AGREEMENT In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and APS. Based on the price reduction formula of
the agreement, the ACC approved retail price decreases of approximately $17.6
million ($10.5 million after income taxes), or 1.2%, effective July 1, 1997;
approximately $17 million ($10 million after income taxes), or 1.1%, effective
July 1, 1998; and approximately $10.8 million ($6.5 million after income taxes),
or 0.7%, effective as of July 1, 1999. The July 1, 1999 rate decrease was
included in the first rate reduction under the Settlement Agreement discussed
above. The regulatory agreement also requires us to infuse $200 million of
common equity into APS in annual payments of $50 million in 1996 through 1999.
-13-
LEGISLATION In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:
* Arizona's largest government-operated electric utility (Salt River Project)
and, at their option, smaller municipal electric systems must (i) make at
least 20% of their 1995 retail peak demand available to electric service
providers by December 31, 1998 and for all retail customers by December 31,
2000; (ii) decrease rates by at least 10% over a ten-year period beginning
as early as January 1, 1991; (iii) implement procedures and public
processes comparable to those already applicable to public service
corporations for establishing the terms, conditions, and pricing of
electric services as well as certain other decisions affecting retail
electric competition;
* describes the factors which form the basis of consideration by Salt River
Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive basis
during the first two years of competition only for customers having demands
in excess of one megawatt (and that are eligible for competitive generation
services), and thereafter for all customers receiving competitive electric
generation.
In addition, the Arizona legislature will review and make recommendations for
the 1999-2000 legislative session on certain competitive issues.
GENERAL We cannot accurately predict the impact of full retail competition
on our financial position, cash flows, or results of operation. As competition
in the electric industry continues to evolve, we will continue to evaluate
strategies and alternatives that will position us to compete in the new
regulatory environment.
FEDERAL The Energy Policy Act of 1992 and recent rulemakings by FERC have
promoted increased competition in the wholesale electric power markets. APS does
not expect these rules to have a material impact on its financial statements.
Several electric utility industry restructuring bills have been introduced
during the 106th Congress. Several of these bills are written to allow consumers
to choose their electricity suppliers beginning in 2000 and beyond. These bills,
other bills that are 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.
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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 competition in the
Arizona electric industry. On February 18, 1999, the ACC approved the Agreement.
The Agreement contains the following major components:
* Both parties amended the Territorial Agreement to remove any barriers in
that agreement to the provision of competitive electricity supply and
non-distribution services.
* Both parties amended 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) became
effective upon the introduction of competition. See Note 6.
8. Nuclear Insurance
The Palo Verde participants have insurance for public liability payments
resulting from nuclear energy hazards to the full limit of liability under
federal law. This potential liability is covered by primary liability insurance
provided by commercial insurance carriers in the amount of $200 million and the
balance by an industry-wide retrospective assessment program. If losses at any
nuclear power plant covered by the programs exceed the accumulated funds, 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.
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9. Accounting Matters
In June 1998 the Financial Accounting Standards Board (FASB) issued SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
requires that entities recognize all derivatives as either assets or liabilities
on the balance sheet and measure those instruments at fair value. The standard
also provides specific guidance for accounting for derivatives designated as
hedging instruments. The statement was to have been effective for us in 2000;
however, the FASB has moved the effective date to 2001. We are currently
evaluating what impact this standard will have on our financial statements.
10. Generation Expansion
We are currently planning a 650-megawatt expansion of our West Phoenix Power
Plant and the construction of a natural, gas-fired electric generating station
of up to 2,120 megawatts near Palo Verde. Projected capital expenditures for
these projects are: 1999, $36 million; 2000, $132 million; and 2001, $240
million. We are also considering additional expansion over the next several
years, which may result in additional expenditures.
Most of the West Phoenix Power Plant expansion (530 megawatts) would be done in
collaboration with Calpine Corporation, an independent power producer. Assuming
all approvals are granted, we expect to begin construction in the second quarter
of 2000.
The new generating station near Palo Verde is planned to consist of four
530-megawatt generating stations, the first of which would come on line in
2002/2003. We expect to begin construction on the first unit in late 2000.
11. Income Tax Benefit
In September 1999, we recorded a tax benefit of $38 million, or $.45 per basic
or diluted share, which stemmed from the resolution of income tax matters
related to a former subsidiary, MeraBank. This amount is reflected as a tax
benefit from discontinued operations in the income statement.
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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, APS Energy Services, and Pinnacle West Energy, 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 SEPTEMBER 30, 1999 COMPARED
WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1998
Consolidated net income for the three months ended September 30, 1999 was $24
million compared with $127 million for the same period in the prior year. Net
income decreased in the three-month comparison primarily because of the effects
of a $140 million after-tax extraordinary charge for a regulatory disallowance
(see Notes 5 and 6) partially offset by the effects of a $38 million income tax
benefit from discontinued operations (see Note 11). Net income excluding the
extraordinary charge and the benefit from discontinued operations was $2 million
lower because of lower net earnings at the subsidiaries.
APS' earnings decreased $141 million in the three-month comparison primarily
because of the effects of a $140 million after-tax extraordinary charge for a
regulatory disallowance (see Notes 5 and 6). APS' earnings excluding the
extraordinary charge were $1 million lower because of the effects of milder
weather, a retail price reduction and lower contributions from power marketing
and trading activities. These reductions in APS' earnings were substantially
offset by an increase in customers and lower property taxes. See Note 6 for
information on the price reduction.
-17-
Electric operating revenues increased $127 million because of:
* increased power marketing and trading revenues ($131 million)
* increases in the number of customers and the average amount of
electricity used by customers ($24 million) and
* miscellaneous factors ($2 million).
As mentioned above, these positive factors were partially offset by weather
impacts ($22 million) and the effect of a reduction in retail prices ($8
million).
Power marketing and trading activities are predominantly short-term opportunity
wholesale sales. The increase in power marketing revenues resulted primarily
from increased activity in western U.S. bulk power markets and was accompanied
by an increase in purchased power expenses. Although these activities contribute
positively to earnings in both periods, the contribution in 1999 was lower than
in 1998.
Fuel and purchased power expenses increased $144 million primarily because of
increased wholesale sales volume and higher purchased power prices.
Other taxes decreased $5 million primarily because of an adjustment to reflect
lower property tax rates for 1999.
OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1998
Consolidated net income for the nine months ended September 30, 1999 was $123
million compared with $207 million for the same period in the prior year. Net
income decreased in the nine-month comparison primarily because of the effects
of a $140 million after-tax extraordinary charge for a regulatory disallowance
(see Notes 5 and 6) partially offset by the effects of a $38 million income tax
benefit from discontinued operations (see Note 11). Net income excluding the
extraordinary charge and the benefit from discontinued operations was $18
million higher because of higher earnings at APS, partially offset by lower
earnings at the other subsidiaries.
APS' earnings decreased $118 million in the nine-month comparison primarily
because of the effects of a $140 million after-tax extraordinary charge for a
regulatory disallowance (see Notes 5 and 6). APS' earnings excluding the
extraordinary charge were $22 million higher because of an increase in
customers, lower property taxes and lower financing costs. These increases in
earnings were partially offset by the effects of milder weather, retail price
reductions, higher depreciation and lower contributions from power marketing and
trading activities. See Note 6 for information on the price reductions.
-18-
Electric operating revenues increased $230 million because of:
* increased power marketing and trading revenues ($188 million) and
* increases in the number of customers and the average amount of
electricity used by customers ($69 million).
As mentioned above, these positive factors were partially offset by weather
impacts ($10 million) and the effect of reductions in retail prices ($17
million).
Power marketing and trading activities are predominantly short-term opportunity
wholesale sales. The increase in power marketing revenues resulted primarily
from increased activity in western U.S. bulk power markets and was accompanied
by an increase in purchased power expenses. Although these activities contribute
positively to earnings in both periods, the contribution in 1999 was lower than
in 1998.
Fuel and purchased power expenses increased $206 million primarily because of
increased wholesale and retail sales volume and higher purchased power prices.
Utility operations and maintenance expense increased $6 million primarily
because of increased power plant overhaul expenses and other costs related to
customer growth, partially offset by lower employee benefits and marketing
costs.
Depreciation and amortization expense increased $8 million because APS had more
plant in service.
Other taxes decreased $6 million primarily because of lower property tax rates
at APS.
Financing costs decreased by $9 million primarily because of lower amounts of
outstanding preferred stock at APS and because the parent company paid down debt
and because of lower interest rates.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 COMPARED
WITH TWELVE-MONTH PERIOD SEPTEMBER 30, 1998
Consolidated net income for the twelve months ended September 30, 1999 was $159
million compared with $226 million for the same period in the prior year. Net
income decreased in the twelve-month comparison primarily because of the effects
of a $140 million after-tax extraordinary charge for a regulatory disallowance
(see Notes 5 and 6) partially offset by the effects of a $38 million income tax
benefit from discontinued operations (see Note 11). Net income excluding the
extraordinary charge and the benefit from discontinued operations was $34
million higher primarily because of higher earnings at APS, partially offset by
lower net earnings at the other subsidiaries.
APS' earnings decreased $102 million in the twelve-month comparison primarily
because of the effects of a $140 million after-tax extraordinary charge for a
regulatory
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disallowance (see Notes 5 and 6). APS' earnings excluding the extraordinary
charge were $38 million higher because of an increase in customers, lower
property taxes, lower operations and maintenance expenses and lower financing
costs. These increases in earnings were partially offset by the effects of
milder weather, retail price reductions and higher depreciation. See Note 6 for
information on the price reductions.
Electric operating revenues increased $266 million because of:
* increased power marketing and trading revenues ($216 million)
* increases in the number of customers and the average amount of
electricity used by customers ($85 million) and
* miscellaneous factors ($8 million).
As mentioned above, these positive factors were partially offset by weather
impacts ($23 million) and the effect of reductions in retail prices ($20
million).
Power marketing and trading activities are predominantly short-term opportunity
wholesale sales. The increase in power marketing revenues resulted primarily
from increased activity in western U.S. bulk power markets and was accompanied
by an increase in purchased power expenses. Although these activities contribute
positively to earnings in both periods, the contribution in the current period
was the same as in the previous period.
Fuel and purchased power expenses increased $228 million primarily because of
increased wholesale and retail sales volume and higher purchased power prices.
Depreciation and amortization expense increased $14 million because APS had more
plant in service.
Other taxes decreased $10 million primarily because of lower property tax rates
for 1999 and an adjustment in the fourth quarter of 1998 to reflect lower
property tax rates for 1998.
Financing costs decreased by $12 million primarily because of lower amounts of
outstanding preferred stock at APS and because the parent company paid down debt
and because of 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. It decreases annual income tax expense by approximately $24 million.
Beginning in 2000, no further benefits from these deferred ITCs will be
reflected in income tax expense.
-20-
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 nine-months ended September 30, 1999, the parent company reduced
long-term borrowings by about $23 million with cash from operations.
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 make the final
investment of $50 million in 1999.
We are currently planning a 650-megawatt expansion of our West Phoenix Power
Plant and the construction of a natural, gas-fired electric generating station
of up to 2,120 megawatts near Palo Verde. Projected capital expenditures for
these projects are: 1999, $36 million; 2000, $132 million; and 2001, $240
million. We are also considering additional expansion over the next several
years, which may result in additional expenditures.
Most of the West Phoenix Power Plant expansion (530 megawatts) would be done in
collaboration with Calpine Corporation, an independent power producer. Assuming
all approvals are granted, we expect to begin construction in the second quarter
of 2000.
The new generating station near Palo Verde is planned to consist of four
530-megawatt generating stations, the first of which would come on line in
2002/2003. We expect to begin construction on the first unit in late 2000.
In October 1999, the Board declared a quarterly dividend of 35 cents per share
of common stock, payable December 1, 1999 to shareholders of record on November
1, 1999, totaling approximately $29.7 million.
APS
For the nine months ended September 30, 1999, APS incurred approximately $229
million in capital expenditures, which is approximately 70% of the most recently
estimated 1999 capital expenditures. APS' projected capital expenditures for the
next three years are: 1999, $328 million; 2000, $353 million; and 2001, $343
million. These amounts include about $30 - $35 million each year for nuclear
fuel expenditures.
-21-
APS' long-term debt and preferred stock redemption requirements, optional
repayments and payment obligations on a capitalized lease for the next three
years are: 1999, $406 million; 2000, $115 million; and 2001, $252 million.
During the nine months ended September 30, 1999, APS redeemed approximately $260
million of its 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, and in
November 1999, APS issued $250 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 make the final investment of $50
million 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 and preferred stock that we may issue, APS does not expect
any of these provisions to limit its ability to meet its capital requirements.
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, delivery, health, and safety
functions) in a timely manner to ensure the reliability of electric service to
its customers. This included a company-wide awareness program of the Year 2000
issue. APS has had an internal audit/quality review of the individual Year 2000
projects and their Year 2000 readiness.
The following chart shows Year 2000 readiness of our mission critical systems as
of September 30, 1999:
Inventory Assessment Remediation & Testing
--------- ---------- ---------------------
APS 100% 100% 100%
Pinnacle West and
other subsidiaries
(excluding APS) 100% 100% 100%
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:
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* 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 and our subsidiaries have made, and will continue to make, certain
modifications to computer hardware, software, and application systems, 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, assessed, remediated and
tested all mission critical IT and non-IT systems and equipment as of September
30, 1999. Remediation and testing is also completed for continuous emissions
monitoring systems (CEMS). See "Year 2000 Readiness Disclosure" in Part I, Item
2 of the June 10-Q. APS notified the North American Electric Reliability Council
(NERC) on June 30, 1999, that its mission critical systems are ready for date
changes associated with the Year 2000, in accordance with NERC's recommended
criteria. APS also notified the Nuclear Regulatory Commission (NRC) that Palo
Verde is "Y2K Ready," which means that Palo Verde has followed a prescribed
program to identify and resolve Year 2000 issues so that the plant can operate
reliably while meeting commitments.
APS has estimated that it would spend approximately $5 million relating to Year
2000 issues, almost all 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. APS funded its cost with available cash balances and cash provided
by operations.
Pinnacle West and its subsidiaries continue to communicate 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
-23-
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 has also been working with 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.
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.
Pinnacle West and its subsidiaries have developed their own contingency plans to
handle Year 2000 issues, including the most reasonably likely worst case
scenario discussed above. These plans were completed June 30, 1999.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 for a discussion of regulatory accounting. See Note 6 for a
discussion of a Settlement Agreement related to the implementation of retail
electric competition. 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 price reduction effective as of July 1, 1999,
and for a discussion of a Settlement Agreement that will, among other things,
result in price reductions over a four-year period ending July 1, 2003.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax, and environmental
legislation; our ability to successfully compete outside our traditional
regulated markets; regional economic conditions, which could
-24-
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; Year 2000
issues, 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.
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.
We are exposed to the impact of market fluctuations in the price and
distribution costs of electricity, natural gas, coal, and emissions
allowances/credits and therefore employ established procedures to manage our
risks associated with these market fluctuations by utilizing various commodity
derivatives, including exchange traded futures and options and over-the-counter
forwards, options, and swaps. As part of our overall risk management program, we
enter into these derivative transactions for trading and to hedge certain
natural gas in storage as well as purchases and sales of electricity, fuels, and
emissions allowances/credits.
We measure the price risk in our commodity derivative portfolio on a daily basis
utilizing market sensitivity based modeling to understand expected and potential
single day favorable or unfavorable impacts to income before tax. The model
results are monitored daily to ensure compliance against thresholds on a
commodity and portfolio basis. As of September 30, 1999, a hypothetical adverse
price movement of 10% in the market price of our commodity derivative portfolio
would decrease the fair market value of these contracts by approximately $7
million. This analysis does not include the favorable impact this same
hypothetical price move would have on the underlying position being hedged with
the commodity derivative portfolio.
We are exposed to credit losses in the event of non-performance or non-payment
by counterparties. We use a credit management process to assess and monitor the
financial exposure of counterparties. We do not expect counterparty defaults to
materially impact our financial condition, results of operations or net cash
flow.
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PART II - OTHER INFORMATION
ITEM 5. OTHER INFORMATION
CONSTRUCTION AND FINANCING PROGRAMS
See "Liquidity and Capital Resources" in Part I, Item 2 of this report for a
discussion of construction and financing programs of the Company and its
subsidiaries.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 6 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 and a settlement
agreement with the ACC.
ENVIRONMENTAL MATTERS
FEDERAL IMPLEMENTATION PLAN. In September 1999, the EPA proposed a Federal
Implementation Plan (FIP) to set air quality standards at certain power plants,
including the Navajo Generating Station and the Four Corners Power Plant. The
comment period on this proposal ends in November 1999. The FIP is similar to
current Arizona regulation of NGS and New Mexico regulation of Four Corners,
with minor modifications. APS does not currently expect the FIP to have a
material impact on its financial position or results of operations.
CLEAN AIR ACT. As previously reported, APS filed a petition for review
alleging EPA improperly classified Four Corners Unit 4 with respect to nitrogen
oxides emissions limitations. See "Environmental Matters - Clean Air Act" in
Part I, Item 1 of the 1998 10-K. In October 1999, EPA issued a direct final
rule, which classified Four Corners Unit 4 as APS had proposed. Depending on the
comments filed by other parties, if any, the rules may become final as soon as
December 1999. APS does not currently expect this rule to have a material impact
on its financial position or results of operations.
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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:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
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
10.3 Settlement Agreement 10.1 to APS' September 30, 1-4473 11-15-99
1999 Form 10-Q Report
10.4 Retail Electric Competition 10.2 to APS' September 30, 1-4473 11-15-99
Rules 1999 Form 10-Q Report
(b) Reports on Form 8-K
During the quarter ended September 30, 1999, and the period from October 1
through November 15, 1999, we filed the following reports on Form 8-K:
Report dated August 26, 1999 regarding the ACC Hearing Officer
recommendations on APS' proposed Settlement Agreement and the proposed retail
electric competition rules.
Report dated September 21, 1999 regarding ACC approval of APS' Settlement
Agreement and the retail electric competition rules.
Report dated September 29, 1999 regarding our plan to construct an electric
generating plant of up to 2,120 megawatts near Palo Verde.
- ----------
(a) Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
-27-
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: November 15, 1999 By: Chris N. Froggatt
------------------------------------
Chris N. Froggatt
Vice President and Controller
(Principal Accounting Officer and
Officer Duly Authorized to sign this
Report)