FORM 10-Q
Securities and Exchange Commission
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 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
----------------------------------------------------
(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 August 12, 1999: 84,764,309
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 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"
El Dorado - El Dorado Investment Company
EPA - Environmental Protection Agency
FASB - Financial Accounting Standards Board
FERC - Federal Energy Regulatory Commission
ITC - Investment tax credit
March 10-Q - Pinnacle West Capital Corporation Quarterly Report on Form 10-Q for
the fiscal quarter ended March 31, 1999
1998 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the
fiscal year ended December 31, 1998
MW - Megawatt, one million watts
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
Power Coordination Agreement - 1955 agreement between the Company and Salt River
Project that provides for certain electric system and power sales
SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"
-2-
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
-3-
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
June 30,
----------------------------
1999 1998
------------ ------------
Operating Revenues
Electric $ 511,434 $ 441,715
Real estate 32,697 28,916
------------ ------------
Total 544,131 470,631
------------ ------------
Operating Expenses
Fuel and purchased power 132,543 95,585
Utility operations and maintenance 106,234 102,713
Real estate operations 29,401 26,213
Depreciation and amortization 97,383 93,585
Taxes other than income taxes 29,602 29,930
------------ ------------
Total 395,163 348,026
------------ ------------
Operating Income 148,968 122,605
------------ ------------
Other Income (Expense)
Preferred stock dividend requirements of APS -- (2,435)
Net other income and expense 399 192
------------ ------------
Total 399 (2,243)
------------ ------------
Income Before Interest and Income Taxes 149,367 120,362
------------ ------------
Interest Expense
Interest charges 41,105 42,441
Capitalized interest (4,189) (4,874)
------------ ------------
Total 36,916 37,567
------------ ------------
Income Before Income Taxes 112,451 82,795
Income Taxes 43,749 33,798
------------ ------------
Net Income $ 68,702 $ 48,997
============ ============
Average Common Shares Outstanding - Basic 84,716,175 84,810,790
Average Common Shares Outstanding - Diluted 85,093,421 85,416,069
Earnings Per Average Common Share Outstanding
Net income - basic $ 0.81 $ 0.58
Net income - diluted $ 0.81 $ 0.57
Dividends Declared Per Share $ 0.65 $ 0.60
============ ============
See Notes to Condensed Consolidated Financial Statements.
-4-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Dollars in thousands, except per share amounts)
Six Months Ended
June 30,
----------------------------
1999 1998
------------ ------------
Operating Revenues
Electric $ 925,417 $ 822,138
Real estate 57,230 63,077
------------ ------------
Total 982,647 885,215
------------ ------------
Operating Expenses
Fuel and purchased power 231,784 169,502
Utility operations and maintenance 205,318 199,129
Real estate operations 51,636 56,449
Depreciation and amortization 194,293 186,415
Taxes other than income taxes 59,049 60,278
------------ ------------
Total 742,080 671,773
------------ ------------
Operating Income 240,567 213,442
------------ ------------
Other Income (Expense)
Preferred stock dividend requirements of APS (1,016) (5,313)
Net other income and expense (1,938) 4,551
------------ ------------
Total (2,954) (762)
------------ ------------
Income Before Interest and Income Taxes 237,613 212,680
------------ ------------
Interest Expense
Interest charges 81,874 85,363
Capitalized interest (8,263) (9,530)
------------ ------------
Total 73,611 75,833
------------ ------------
Income Before Income Taxes 164,002 136,847
Income Taxes 64,610 56,764
------------ ------------
Net Income $ 99,392 $ 80,083
============ ============
Average Common Shares Outstanding - Basic 84,693,115 84,798,120
Average Common Shares Outstanding - Diluted 85,135,423 85,375,609
Earnings Per Average Common Share Outstanding
Net income - basic $ 1.17 $ 0.94
Net income - diluted $ 1.17 $ 0.94
Dividends Declared Per Share $ 0.975 $ 0.90
============ ============
See Notes to Condensed Consolidated Financial Statements.
-5-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Dollars in thousands, except per share amounts)
Twelve Months Ended
June 30,
----------------------------
1999 1998
------------ ------------
Operating Revenues
Electric $ 2,109,677 $ 1,862,919
Real estate 118,341 129,841
------------ ------------
Total 2,228,018 1,992,760
------------ ------------
Operating Expenses
Fuel and purchased power 599,783 421,350
Utility operations and maintenance 420,230 421,385
Real estate operations 110,518 120,014
Depreciation and amortization 387,557 370,289
Taxes other than income taxes 115,677 121,269
------------ ------------
Total 1,633,765 1,454,307
------------ ------------
Operating Income 594,253 538,453
------------ ------------
Other Income (Expense)
Preferred stock dividend requirements of APS (5,406) (11,295)
Net other income and expense (5,880) 74
------------ ------------
Total (11,286) (11,221)
------------ ------------
Income Before Interest and Income Taxes 582,967 527,232
------------ ------------
Interest Expense
Interest charges 165,656 176,207
Capitalized interest (17,329) (19,223)
------------ ------------
Total 148,327 156,984
------------ ------------
Income Before Income Taxes 434,640 370,248
Income Taxes 172,439 146,873
------------ ------------
Net Income $ 262,201 $ 223,375
============ ============
Average Common Shares Outstanding - Basic 84,722,147 84,767,601
Average Common Shares Outstanding - Diluted 85,232,428 85,298,571
Earnings Per Average Common Share Outstanding
Net income - basic $ 3.09 $ 2.64
Net income - diluted $ 3.08 $ 2.62
Dividends Declared Per Share $ 1.30 $ 1.20
============ ============
See Notes to Condensed Consolidated Financial Statements.
-6-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Thousands of Dollars)
June 30, December 31,
1999 1998
(Unaudited)
---------- ----------
Current Assets
Cash and cash equivalents $ 32,511 $ 20,538
Customer and other receivables--net 185,701 233,876
Accrued utility revenues 98,046 67,740
Materials and supplies 70,919 69,074
Fossil fuel 17,786 13,978
Deferred income taxes 4,058 3,999
Other current assets 55,923 47,594
---------- ----------
Total current assets 464,944 456,799
---------- ----------
Investments and Other Assets
Real estate investments--net 335,977 331,021
Other assets 262,586 236,562
---------- ----------
Total investments and other assets 598,563 567,583
---------- ----------
Utility Plant
Electric plant in service and held for future use 7,370,852 7,265,604
Less accumulated depreciation and amortization 2,941,878 2,814,762
---------- ----------
Total 4,428,974 4,450,842
Construction work in progress 247,910 228,643
Nuclear fuel, net of amortization 50,446 51,078
---------- ----------
Net utility plant 4,727,330 4,730,563
---------- ----------
Deferred Debits
Regulatory asset for income taxes 373,417 400,795
Rate synchronization cost deferral 276,055 303,660
Other deferred debits 363,912 365,146
---------- ----------
Total deferred debits 1,013,384 1,069,601
---------- ----------
Total Assets $6,804,221 $6,824,546
========== ==========
See Notes to Condensed Consolidated Financial Statements.
-7-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
(Thousands of Dollars)
June 30, December 31,
1999 1998
(Unaudited)
---------- ----------
Current Liabilities
Accounts payable $ 127,791 $ 155,800
Accrued taxes 158,195 62,520
Accrued interest 32,972 31,866
Dividends payable 27,552 --
Short-term borrowings 223,950 178,830
Current maturities of long-term debt 17,810 168,045
Customer deposits 25,943 28,510
Other current liabilities 5,806 14,632
---------- ----------
Total current liabilities 620,019 640,203
---------- ----------
Long-Term Debt Less Current Maturities 2,164,459 2,048,961
---------- ----------
Deferred Credits and Other
Deferred income taxes 1,319,340 1,343,536
Deferred investment tax credit 19,672 27,345
Unamortized gain - sale of utility plant 75,499 77,787
Other 435,351 428,122
---------- ----------
Total deferred credits and other 1,849,862 1,876,790
---------- ----------
Commitments and contingencies (Notes 5, 6, 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 1,540,437 1,550,643
Retained earnings 629,444 612,708
---------- ----------
Total common stock equity 2,169,881 2,163,351
---------- ----------
Total Liabilities and Equity $6,804,221 $6,824,546
========== ==========
See Notes to Condensed Consolidated Financial Statements.
-8-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(THOUSANDS OF DOLLARS)
Six Months Ended
June 30,
----------------------
1999 1998
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 99,392 $ 80,083
Items not requiring cash
Depreciation and amortization 194,293 186,415
Nuclear fuel amortization 15,673 16,580
Deferred income taxes--net (21,477) 5,645
Deferred investment tax credit (7,673) (7,895)
Other--net 1,096 782
Changes in current assets and liabilities
Customer and other receivables--net 48,175 12,544
Accrued utility revenues (30,306) (8,363)
Materials, supplies and fossil fuel (5,653) (8,912)
Other current assets (8,329) (5,314)
Accounts payable (25,465) (12,438)
Accrued taxes 95,675 (8,081)
Accrued interest 1,106 (349)
Other current liabilities (5,307) 5,339
Decrease (increase) in land held (4,642) 15,084
Other--net (16,382) (7,364)
--------- ---------
Net Cash Flow Provided By Operating Activities 330,176 263,756
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (153,730) (144,580)
Capitalized interest (8,263) (9,530)
Other--net 1,282 15,485
--------- ---------
Net Cash Flow Used For Investing Activities (160,711) (138,625)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 193,691 99,375
Short-term borrowings--net 45,120 82,735
Dividends paid on common stock (55,101) (50,878)
Repayment of long-term debt (235,755) (220,782)
Redemption of preferred stock (96,499) (31,209)
Other--net (8,948) (215)
--------- ---------
Net Cash Flow Used For Financing Activities (157,492) (120,974)
--------- ---------
Net Cash Flow 11,973 4,157
Cash and Cash Equivalents at Beginning of Period 20,538 27,484
========= =========
Cash and Cash Equivalents at End of Period $ 32,511 $ 31,641
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 68,341 $ 72,863
Income taxes $ 940 $ 64,820
See Notes to Condensed Consolidated Financial Statements.
-9-
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 six months ended June 30, 1999.
5. 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 $850
million at June 30, 1999. Under the 1996 regulatory agreement (see Note 7), 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.
-10-
Although rules have been proposed for the transition of generation services to
competition, there are many unresolved issues. APS continues to apply SFAS No.
71 to its 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. See Note 6 for a discussion of a proposed settlement agreement which,
if approved, would result in the discontinuation of SFAS No. 71 for generation
operations.
6. Regulatory Matters -- Electric Industry Restructuring
STATE
PROPOSED 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. Hearings before the ACC on the Settlement Agreement
ended in July 1999, and a final ACC order, which is a condition to the
agreement's effectiveness, has not yet been issued. By the terms of the
Settlement Agreement, unless ACC approval has been obtained on or before August
1, 1999, each party has the right to unilaterally withdraw from the Settlement
Agreement. To date, no party has elected to withdraw.
The following are the major provisions of the Settlement Agreement:
* 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 includes the July 1, 1999 retail price decrease related to the
1996 regulatory agreement. See Note 7. 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) will become effective as of July 1,
1999, and 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.
* 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.
-11-
* APS' distribution system will be open for retail access upon approval of
the Settlement Agreement. Customers will be eligible for retail access in
accordance with the phase-in program expected to be ultimately adopted by
the ACC under the electric competition rules when such rules become
effective, 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. See Note
7. 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 against the costs subject to recovery under the adjustment
clause described above.
* APS will form a separate corporate affiliate or affiliates and transfer
thereto its generating assets and competitive services by December 31,
2002.
* Upon final approval of the Settlement Agreement by the ACC in an order no
longer subject to judicial review, APS will move to dismiss all of its
litigation pending against the ACC as of the date of the Settlement
Agreement.
Upon final ACC order, APS will discontinue the application of Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation," for its generation operations. This means that regulatory
assets, unless reestablished as recoverable through ongoing regulated cash
flows, are to be eliminated and the generation assets must be tested for
impairment. The regulatory disallowance, which removes $234 million pre-tax
($183 million net present value) from ongoing regulatory cash flows, will be
recorded as a net reduction of regulatory assets. This reduction will be
reported as an extraordinary charge on the income statement. The regulatory
assets to be recovered under this Settlement Agreement would be amortized as
follows:
(Millions)
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
- -------- -------- -------- -------- -------- -------- --------
$164 $158 $145 $115 $86 $18 $686
-12-
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 ACC adopted certain modifications to these rules on
August 10, 1998, and on December 11, 1998, the ACC adopted the amended rules,
without any modifications that would have a significant impact on APS, on a
permanent basis. 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 recommended changes, with certain exceptions (the "Proposed Rules").
The Proposed Rules approved by the ACC for further rulemaking include the
following major provisions:
* They would apply to virtually all Arizona electric utilities regulated by
the ACC, including APS.
* The Proposed 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.
-13-
* Affected utilities must file ACC tariffs with separate pricing for electric
services provided for noncompetitive services.
* The 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 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 were held
in June 1999, and a final order has not yet been issued.
We cannot currently predict when or if the Proposed Rules will become effective,
when or if the stay of the amended rules will be lifted, or when retail electric
competition will be introduced in Arizona. See "Proposed Settlement Agreement"
above for discussion of APS' proposals regarding the introduction of retail
electric competition 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 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.
-14-
* 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.
See "Proposed Settlement Agreement" above, for a discussion of the methodology
APS proposed.
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 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.
-15-
GENERAL 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. See "Proposed
Settlement Agreement" above.
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.
7. 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. In May 1999, APS filed with the ACC for
another retail price decrease of approximately $10.8 million annually ($6.5
million after income taxes), which would become effective as of 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
-16-
agreement and will be included in the first rate reduction under the proposed
Settlement Agreement discussed in Note 6. See "Proposed Settlement Agreement"
above for a discussion of the price decrease.
8. 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 amended the Territorial Agreement to remove any barriers in
that agreement 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 6. On February 18,
1999, the ACC approved the Agreement.
9. 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
-17-
insurance coverage discussed in this and the previous paragraph is subject to
certain policy conditions and exclusions.
10. 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.
11. Memorandum of Understanding with Calpine Corporation
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 megawatt expansion at the site of APS' West
Phoenix Power Plant. We entered into a further memorandum of understanding with
Calpine dated as of August 4, 1999, relating to the timing of the definitive
agreements and the operation of the joint project. The joint project is the
second phase of a potential 750 megawatt expansion at West Phoenix, the first
phase of which includes the installation of a 120 megawatt combined cycle unit,
the cost of which is expected to be approximately $60 million, although that
amount is currently subject to negotiation. Assuming approvals are granted,
construction is scheduled to begin in mid-2000, with commercial operation of the
first phase in mid-2001 and the second phase in early 2002.
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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 JUNE 30, 1999 COMPARED WITH
THREE-MONTH PERIOD ENDED JUNE 30, 1998
Consolidated net income for the three months ended June 30, 1999 was $68.7
million compared with $49.0 million for the same period in the prior year. Net
income increased in the three-month comparison primarily because of higher
earnings at APS.
APS' earnings increased $19.8 million in the three-month comparison primarily
because of the effects of warmer weather, an increase in customers, and
increased contributions from power marketing and trading activities, partially
offset by a retail price reduction, and higher depreciation and amortization
expense. See Note 7 for information on the price reduction.
Electric operating revenues increased $70 million because of:
* increased power marketing and trading revenues ($36 million)
* the effects of warmer weather ($21 million) and
* increases in the number of customers ($17 million).
As mentioned above, these positive factors were partially offset by the effect
of a reduction in retail prices ($4 million).
-19-
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 bulk power markets. The increase in power
marketing and trading revenues was accompanied by increases in purchased power
expenses.
Fuel expenses increased $37 million primarily because of increased wholesale and
retail sales volume and higher purchased power prices.
Depreciation and amortization expense increased $4 million because APS had more
plant in service.
OPERATING RESULTS - SIX-MONTH PERIOD ENDED JUNE 30, 1999 COMPARED WITH
SIX-MONTH PERIOD ENDED JUNE 30, 1998
Consolidated net income for the six months ended June 30, 1999 was $99.4 million
compared with $80.1 million for the same period in the prior year. Net income
increased in the six-month comparison primarily because of higher earnings at
APS, partially offset by lower earnings at El Dorado.
APS earnings increased $23.5 million in the six-month comparison primarily
because of an increase in customers, increased contributions from power
marketing and trading activities, and the effects of warmer weather, partially
offset by a retail price reduction, and higher depreciation and amortization
expense. See Note 7 for information on the price reduction.
Electric operating revenues increased $103 million because of:
* increased power marketing and trading revenues ($70 million)
* increases in the number of customers ($29 million)
* the effects of warmer weather ($10 million) and
* miscellaneous factors ($2 million).
As mentioned above, these positive factors were partially offset by 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 from
increased activity in western bulk power markets. The increase in power
marketing and trading revenues was accompanied by increases in purchased power
expenses.
Fuel expenses increased $62 million primarily because of increased wholesale and
retail sales volume and higher purchased power prices.
Depreciation and amortization expense increased $8 million because APS had more
plant in service.
El Dorado's earnings decreased $4 million because of investment sales in 1998.
-20-
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED JUNE 30, 1999 COMPARED WITH
TWELVE-MONTH PERIOD ENDED JUNE 30, 1998
Consolidated net income for the twelve months ended June 30, 1999 was $262.2
million compared with $223.4 million for the same period in the prior year. Net
income increased in the twelve-month comparison primarily because of higher
earnings at APS and lower financing costs at the parent, partially offset by
lower contributions to earnings by the other subsidiaries.
APS earnings increased $42.9 million in the twelve-month comparison primarily
because of an increase in customers, increased contributions from power
marketing and trading activities, the effects of warmer weather, and lower
financing costs. In the comparison, these positive factors more than offset the
effects of two fuel-related settlements recorded in the third quarter of 1997, a
retail price reduction that became effective July 1, 1998, and higher
depreciation and amortization expense. See Note 7 for additional information
about the price reduction.
Operating revenues increased $247 million primarily because of:
* increased power marketing and trading revenues ($164 million)
* increases in the number of customers and the average amount of
electricity used by customers ($79 million)
* the effects of warmer weather ($15 million) and
* miscellaneous factors ($7 million).
As mentioned above, these positive factors were partially offset by the effect
of a reduction in retail prices ($18 million).
Power marketing and trading activities are predominantly short-term opportunity
wholesale sales. The increase in power marketing revenues resulted from
increased activity in Western bulk power markets, higher prices, and increased
sales to large customers in California. The increase in power marketing and
trading revenues was accompanied by increases in purchased power expenses.
Fuel expense increased $178 million primarily because of increased wholesale and
retail sales volumes, the effects of two fuel-related settlements in the third
quarter of 1997, and higher purchased power prices. The settlements increased
pretax earnings in the twelve months ended June 30, 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 $17 million because APS had more
plant in service.
APS decreased its financing costs by $10 million primarily because of lower
amounts of outstanding debt and preferred stock and lower interest rates.
-21-
Parent company financing costs decreased $7 million as we paid down debt and
took advantage of lower interest rates.
El Dorado's earnings decreased $5 million in the twelve-month period because of
investment sales in 1998 and 1997.
APS Energy Services, which was incorporated in late 1998, reported a loss of $3
million for the twelve-month period.
OTHER INCOME
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 six-months ended June 30, 1999, the parent company redeemed
approximately $19 million of its long-term debt with cash from operations and
proceeds from long-term borrowings.
As a result of the 1996 regulatory agreement (see Note 7), 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.
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 megawatt expansion at the site of APS' West
Phoenix Power Plant. We entered into a further memorandum of understanding with
Calpine dated as of August 4, 1999, relating to the timing of the definitive
agreements and the operation of the joint project. The joint project is the
second phase of a potential 750 megawatt expansion at West Phoenix, the first
phase of which includes the installation of a 120 megawatt combined cycle unit,
the cost of which is expected to be approximately $60 million, although that
amount is currently subject to negotiation. Assuming approvals are granted,
construction is scheduled to begin in mid-2000, with commercial operations of
the first phase in mid-2001 and of the second phase in early 2002. 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
-22-
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 September 1, 1999 to shareholders of record on August 2, 1999, totaling
approximately $27.6 million.
APS
For the six months ended June 30, 1999, APS incurred approximately $154 million
in capital expenditures, which is approximately 47% 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.
APS' long-term debt and preferred stock redemption requirements and payment
obligations on a capitalized lease for the next three years are: 1999, $387
million; 2000, $115 million; and 2001, $2 million. During the six months ended
June 30, 1999, APS redeemed approximately $216 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. As a result of the 1996 regulatory
agreement (see Note 7), 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 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 an internal audit/quality review team that is periodically
reviewing the individual Year 2000 projects and their Year 2000 readiness.
-23-
The following chart shows Year 2000 readiness of our mission critical systems as
of June 30, 1999:
Inventory Assessment Remediation & Testing
--------- ---------- ---------------------
APS 100% 100% 100%
Pinnacle West and
other subsidiaries
(excluding APS) 100% 100% 95%(1)
(1) 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.
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 and assessed essentially all
mission critical IT and non-IT systems and equipment. APS is 100% complete and
Pinnacle West and its other subsidiaries are 95% complete with the remediation
and testing of these systems. 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
-24-
and resolve Year 2000 issues so that the plant can operate reliably while
meeting commitments.
As previously reported, APS expected remediation and testing to be completed by
June 30, 1999, for all mission critical systems, except for (i) Palo Verde Unit
1 systems and (ii) the continuous emissions monitoring systems (CEMS) for four
of its fossil plants. See "Year 2000 Readiness Disclosure" in Part I, Item 2 of
the March 10-Q. However, as of June 30, 1999, remediation and testing was
completed for all mission critical systems, including Palo Verde Unit 1, but
excluding CEMS, which have been removed from the mission critical systems list
because the failure of the system would not lead to an unplanned shutdown of
generation. This is based on NERC's June 14, 1999 clarifying pronouncement on
exception reporting. APS currently expects the CEMS for the four fossil plants
to be Y2K Ready no later than the fourth quarter 1999.
APS currently estimates that it will spend approximately $5 million relating to
Year 2000 issues, about $4.5 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 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.
-25-
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 proposed Settlement Agreement related to the implementation of
retail electric competition. See Note 8 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 7 for a discussion of a proposed price reduction that would become
effective as of July 1, 1999. See Note 6 for a discussion of a proposed
Settlement Agreement that would, among other things, result in rate 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; 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; 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
-26-
has risks associated with changing market values of equity investments. Nuclear
decommissioning costs are recovered in rates.
APS is exposed to the impact of market fluctuations in the price and
distribution costs of electricity, natural gas, coal, and emissions and
therefore employs established procedures to manage its 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 its overall risk management program, APS enters 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.
APS measures the price risk in its 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 June 30, 1999, a hypothetical adverse price
movement of 10% in the market price of APS' commodity derivative portfolio would
decrease the fair market value of these contracts by approximately $8 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.
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 exposure of counterparties. APS does not expect counterparty
defaults to materially impact its financial condition, results of operations, or
net cash flows.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In June 1999, the Navajo Nation served Salt River Project with a lawsuit naming
Salt River Project, several Peabody Coal Company entities ("Peabody"), Southern
California Edison Company, and other defendants, and citing various claims in
connection with the renegotiations of the coal royalty and lease agreements
under which Peabody mines coal for the Navajo and Mohave Generating Stations.
THE NAVAJO NATION V. PEABODY HOLDING COMPANY, INC., ET AL., United States
District Court for the District of Columbia, No. CA-99-0469-EGS. APS is a 14%
owner of Navajo Generating Station, which Salt River Project operates. The suit
alleges, among other things, that the defendants obtained a favorable coal
royalty rate by improperly influencing the outcome of a federal administrative
process under which the royalty rate was to be adjusted. The suit seeks $600
million in damages, treble damages, punitive damages of not less than $1
billion, and the ejection of defendants "from all possessory interests and
Navajo Tribal lands" arising out of the [primary coal lease]. Salt River Project
has advised APS that it denies all charges and will vigorously defend itself.
Because the litigation is in preliminary stages, APS cannot currently predict
the outcome of this matter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
At our annual Meeting of Shareholders held on May 19, 1999 the following
shareholder proposal was submitted to shareholders:
Abstentions
Votes Votes and Broker
For Against Non Votes
----- ------- -----------
Proposal that Pinnacle 2,413,519 63,160,240 2,955,431
West refuse to use
plutonium (MOX) fuel and
refuse to generate tritium
In addition, at the same annual meeting, the following persons were elected
Class II Directors with a term to expire at the 2002 annual meeting of
shareholders:
Abstentions
Votes Votes and Broker
For Withheld Non Votes
----- ------- -----------
Edward N. Basha 78,205,297 1,528,855 N/A
Michael L. Gallagher 78,246,095 1,488,057 N/A
William J. Post 78,396,955 1,337,197 N/A
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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 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 proposed
settlement agreement with the ACC.
ENVIRONMENTAL MATTERS
As previously reported, in July 1997, EPA promulgated final national ambient air
quality standards for ozone and coarse and fine particulate matter. See
"Environmental Matters - EPA Environmental Regulation - Clear Air Act" in Part
I, Item 1 of the 1998 10-K. These standards were challenged and the court
determined that EPA's promulgation of the standards violated the constitutional
prohibition on delegation of legislative power. The court remanded the ozone
standard, vacated the coarse particulate matter standard, and invited the
parties to brief the court on vacating or remanding the fine particulate matter
standard. APS cannot currently predict EPA's response to this decision.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
- ----------- -----------
10.1(a) Key Executive Employment and Severance Agreement between
Pinnacle West and certain executive officers of Pinnacle West
and its subsidiaries
27.1 Financial Data Schedule
- ----------
(a) Additional agreements, substantially identical in all material respects to
this Exhibit have been entered into with additional officers of Pinnacle West
and its subsidiaries. Although such additional documents may differ in other
respects (such as dollar amounts and dates of execution), there are no material
details in which such agreements differ from this Exhibit.
-29-
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.(b) 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
(b) Reports on Form 8-K
During the quarter ended June 30, 1999, and the period from July 1 through
August 16, 1999, we filed the following reports on Form 8-K:
Report dated March 22, 1999 relating to Pinnacle West's amended and
restated stockholder rights plan, effective March 26, 1999.
Report dated May 14, 1999 regarding the settlement agreement between APS
and various other parties, including representatives of major consumer groups,
related to the implementation of retail electric competition.
- ----------
(b) Reports filed under File No. 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
-30-
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: August 16, 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)