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, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________________ to ________________
Commission file number 1-8962
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 November 10, 2000: 84,710,644
<PAGE>
Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
APS - Arizona Public Service Company, a Pinnacle West subsidiary
APS Energy Services - APS Energy Services Company, Inc., a Pinnacle West
subsidiary
Company - Pinnacle West Capital Corporation
CPUC - California Public Utilities Commission
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, a Pinnacle West subsidiary
EPA - United States Environmental Protection Agency
FASB - Financial Accounting Standards Board
FERC - United States 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, 2000
MW - Megawatts
NGS - Navajo Generating Station
1999 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the
fiscal year ended December 31, 1999
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West
subsidiary
SCE - Southern California Edison Company, a subsidiary of Edison International
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
Settlement Agreement - APS' Settlement Agreement approved by the ACC in 1999
SunCor - SunCor Development Company, a Pinnacle West subsidiary
<PAGE>
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
Three Months Ended
September 30,
-------------------------
2000 1999
----------- ---------
<S> <C> <C>
Operating Revenues
Electric $ 1,567,960 $ 867,630
Real estate 39,396 26,640
----------- ---------
Total 1,607,356 894,270
----------- ---------
Operating Expenses
Fuel and purchased power 1,079,436 400,961
Operations and maintenance 113,670 109,006
Real estate operations 33,980 26,757
Depreciation and amortization 98,628 95,068
Taxes other than income taxes 25,641 22,184
----------- ---------
Total 1,351,355 653,976
----------- ---------
Operating Income 256,001 240,294
Other Income (Expense) (14,778) 1,040
----------- ---------
Income From Continuing Operations Before
Interest and Income Taxes 241,223 241,334
----------- ---------
Interest Expense
Interest charges 42,773 39,614
Capitalized interest (5,240) (1,990)
----------- ---------
Total 37,533 37,624
----------- ---------
Income From Continuing Operations Before Income Taxes 203,690 203,710
Income Taxes 87,641 78,131
----------- ---------
Income From Continuing Operations 116,049 125,579
Income Tax Benefit From Discontinued Operations -- 38,000
Extraordinary Charge - Net of Income Taxes of $94,115 -- (139,885)
----------- ---------
Net Income $ 116,049 $ 23,694
=========== =========
Average Common Shares Outstanding - Basic 84,745 84,759
Average Common Shares Outstanding - Diluted 85,012 84,989
Earnings Per Average Common Share Outstanding
Continuing Operations - Basic $ 1.37 $ 1.48
Net Income - Basic $ 1.37 $ 0.28
Continuing Operations - Diluted $ 1.37 $ 1.48
Net Income - Diluted $ 1.37 $ 0.28
Dividends Declared Per Share $ 0.35 $ --
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
<PAGE>
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
---------------------------
2000 1999
----------- -----------
<S> <C> <C>
Operating Revenues
Electric $ 2,734,362 $ 1,793,047
Real estate 117,659 83,870
----------- -----------
Total 2,852,021 1,876,917
----------- -----------
Operating Expenses
Fuel and purchased power 1,495,218 636,062
Operations and maintenance 331,754 319,212
Real estate operations 101,374 78,393
Depreciation and amortization 293,607 289,361
Taxes other than income taxes 76,643 73,028
----------- -----------
Total 2,298,596 1,396,056
----------- -----------
Operating Income 553,425 480,861
----------- -----------
Other Income (Expense)
Preferred stock dividend requirements of APS -- (1,016)
Net other income and expense 13,785 (898)
----------- -----------
Total 13,785 (1,914)
----------- -----------
Income From Continuing Operations Before
Interest and Income Taxes 567,210 478,947
----------- -----------
Interest Expense
Interest charges 126,996 121,488
Capitalized interest (13,875) (10,253)
----------- -----------
Total 113,121 111,235
----------- -----------
Income From Continuing Operations Before Income Taxes 454,089 367,712
Income Taxes 194,069 142,741
----------- -----------
Income From Continuing Operations 260,020 224,971
Income Tax Benefit From Discontinued Operations -- 38,000
Extraordinary Charge - Net of Income Taxes of $94,115 -- (139,885)
----------- -----------
Net Income $ 260,020 $ 123,086
=========== ===========
Average Common Shares Outstanding - Basic 84,735 84,715
Average Common Shares Outstanding - Diluted 84,901 85,087
Earnings Per Average Common Share Outstanding
Continuing Operations - Basic $ 3.07 $ 2.66
Net Income - Basic $ 3.07 $ 1.45
Continuing Operations - Diluted $ 3.06 $ 2.64
Net Income - Diluted $ 3.06 $ 1.45
Dividends Declared Per Share $ 1.05 $ 0.975
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
<PAGE>
-4-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
Twelve Months Ended
September 30,
---------------------------
2000 1999
----------- -----------
<S> <C> <C>
Operating Revenues
Electric $ 3,234,499 $ 2,236,573
Real estate 163,958 126,705
----------- -----------
Total 3,398,457 2,363,278
----------- -----------
Operating Expenses
Fuel and purchased power 1,655,265 752,832
Operations and maintenance 459,319 425,239
Real estate operations 142,497 118,454
Depreciation and amortization 389,814 387,644
Taxes other than income taxes 100,221 96,400
----------- -----------
Total 2,747,116 1,780,569
----------- -----------
Operating Income 651,341 582,709
----------- -----------
Other Income (Expense)
Preferred stock dividend requirements of APS -- (3,059)
Net other income and expense 25,476 (3,329)
----------- -----------
Total 25,476 (6,388)
----------- -----------
Income From Continuing Operations Before
Interest and Income Taxes 676,817 576,321
----------- -----------
Interest Expense
Interest charges 167,889 163,224
Capitalized interest (15,286) (14,588)
----------- -----------
Total 152,603 148,636
----------- -----------
Income From Continuing Operations Before Income Taxes 524,214 427,685
Income Taxes 219,393 167,186
----------- -----------
Income From Continuing Operations 304,821 260,499
Income Tax Benefit From Discontinued Operations -- 38,000
Extraordinary Charge - Net of Income Taxes of $94,115 -- (139,885)
----------- -----------
Net Income $ 304,821 $ 158,614
=========== ===========
Average Common Shares Outstanding - Basic 84,732 84,719
Average Common Shares Outstanding - Diluted 84,898 85,140
Earnings Per Average Common Share Outstanding
Continuing Operations - Basic $ 3.60 $ 3.07
Net Income - Basic $ 3.60 $ 1.87
Continuing Operations - Diluted $ 3.59 $ 3.06
Net Income - Diluted $ 3.59 $ 1.86
Dividends Declared Per Share $ 1.40 $ 1.30
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
<PAGE>
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Thousands of Dollars)
September 30, December 31,
2000 1999
---------- ----------
(Unaudited)
Current Assets
Cash and cash equivalents $ 87,682 $ 20,705
Customer and other receivables--net 669,858 244,599
Accrued utility revenues 111,315 72,919
Materials and supplies 73,506 69,977
Fossil fuel 14,553 21,869
Deferred income taxes 10,081 8,163
Other current assets 71,531 60,562
---------- ----------
Total current assets 1,038,526 498,794
---------- ----------
Investments and Other Assets
Real estate investments--net 366,386 344,293
Other assets 249,157 267,458
---------- ----------
Total investments and other assets 615,543 611,751
---------- ----------
Property, Plant and Equipment
Plant in service and held for future use 7,727,739 7,546,314
Less accumulated depreciation and
amortization 3,194,323 3,026,194
---------- ----------
Total 4,533,416 4,520,120
Construction work in progress 362,472 209,281
Nuclear fuel, net of amortization 51,274 49,114
---------- ----------
Net property, plant and equipment 4,947,162 4,778,515
---------- ----------
Deferred Debits
Regulatory assets 502,595 613,729
Other deferred debits 70,954 105,717
---------- ----------
Total deferred debits 573,549 719,446
---------- ----------
Total Assets $7,174,780 $6,608,506
========== ==========
See Notes to Condensed Consolidated Financial Statements.
<PAGE>
-6-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
(Thousands of Dollars)
September 30, December 31,
2000 1999
---------- ----------
(Unaudited)
Current Liabilities
Accounts payable $ 498,161 $ 186,524
Accrued taxes 231,738 70,510
Accrued interest 26,410 33,253
Short-term borrowings 1,984 38,300
Current maturities of long-term debt 4,887 114,798
Customer deposits 25,603 26,098
Other current liabilities 45,820 26,007
---------- ----------
Total current liabilities 834,603 495,490
---------- ----------
Long-Term Debt Less Current Maturities 2,354,911 2,206,052
---------- ----------
Deferred Credits and Other
Deferred income taxes 1,108,274 1,183,855
Unamortized gain - sale of utility plant 69,780 73,212
Other 431,380 444,164
---------- ----------
Total deferred credits and other 1,609,434 1,701,231
---------- ----------
Commitments and Contingencies (Notes 6, 7, 9 and 10)
Common Stock Equity
Common stock, no par value 1,536,493 1,537,449
Retained earnings 839,339 668,284
---------- ----------
Total common stock equity 2,375,832 2,205,733
---------- ----------
Total Liabilities and Equity $7,174,780 $6,608,506
========== ==========
See Notes to Condensed Consolidated Financial Statements.
<PAGE>
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(thousands of dollars)
Nine Months Ended
September 30,
-----------------------
2000 1999
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income From Continuing Operations $ 260,020 $ 224,971
Items not requiring cash
Depreciation and amortization 293,607 289,361
Nuclear fuel amortization 23,139 24,306
Deferred income taxes--net (42,984) (74,670)
Other--net (3,350) (18,908)
Changes in current assets and liabilities
Customer and other receivables--net (425,259) (106,815)
Accrued utility revenues (38,396) (33,543)
Materials, supplies and fossil fuel 3,787 (4,758)
Other current assets (10,969) (12,055)
Accounts payable 308,407 81,805
Accrued taxes 161,228 130,371
Accrued interest (6,843) (7,871)
Other current liabilities 24,845 13,964
Change in El Dorado partnership investment (11,897) --
Increase in land held (21,073) (4,237)
Other--net 38,717 28,431
--------- ---------
Net Cash Flow Provided By Operating Activities 552,979 530,352
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (398,994) (235,568)
Capitalized interest (13,875) (10,253)
Other--net 20,259 (5,567)
--------- ---------
Net Cash Flow Used For Investing Activities (392,610) (251,388)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 494,000 249,191
Short-term borrowings--net (36,316) 44,670
Dividends paid on common stock (88,963) (82,652)
Repayment of long-term debt (461,157) (379,936)
Redemption of preferred stock -- (96,499)
Other--net (956) (10,250)
--------- ---------
Net Cash Flow Used For Financing Activities (93,392) (275,476)
--------- ---------
Net Cash Flow 66,977 3,488
Cash and Cash Equivalents at Beginning of Period 20,705 20,538
--------- ---------
Cash and Cash Equivalents at End of Period $ 87,682 $ 24,026
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 109,778 $ 109,702
Income taxes $ 127,013 $ 95,590
See Notes to Condensed Consolidated Financial Statements.
<PAGE>
-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, Pinnacle West Energy, APS Energy
Services, SunCor, and El Dorado . 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 the exception of the
extraordinary charge 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 1999 10-K.
3. Weather conditions and wholesale power marketing and trading activities can
have significant impacts on our results for interim periods. El Dorado's
earnings are subject to stock market volatility (see Note 12). For these 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, 2000.
5. Regulatory Accounting
For regulated operations, APS prepares its financial statements in accordance
with 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 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.
The Settlement Agreement was approved by the ACC in September 1999 (see Note 6
for a discussion of the agreement). Consequently, APS has discontinued the
application of SFAS No. 71 for its generation operations. This application means
that the generation assets were tested for impairment and the portion of
regulatory assets deemed to be unrecoverable through ongoing regulated cash
flows was eliminated. APS determined that the generation assets were not
impaired. A regulatory disallowance removed $234 million pretax ($183 million
net present value) from ongoing regulatory cash flows and was recorded as a net
reduction of regulatory assets. This reduction ($140 million after income taxes)
was reported as an extraordinary charge on the consolidated income statement
during the third quarter of 1999. Prior to the Settlement Agreement, under the
1996 regulatory agreement (see Note 6), the ACC accelerated the amortization of
substantially all of APS' regulatory assets to an eight-year period ending June
30, 2004.
<PAGE>
-9-
The regulatory assets to be recovered under the 1999 Settlement Agreement are
now being amortized as follows (millions of dollars):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $ 86 $ 18 $686
The majority of APS' regulatory assets relate to deferred income taxes and rate
synchronization cost deferrals.
The condensed consolidated balance sheets include the amounts listed below for
generation assets not subject to SFAS No. 71 (thousands of dollars):
September 30, December 31,
2000 1999
----------- -----------
Electric plant in service & held for future use $ 3,819,709 $ 3,770,234
Accumulated depreciation and amortization (1,725,706) (1,641,855)
Construction work in progress 224,760 87,819
Nuclear fuel, net of amortization 51,274 49,114
6. Regulatory Matters -- Electric Industry Restructuring
STATE
SETTLEMENT AGREEMENT. On May 14, 1999, APS entered into a comprehensive
Settlement Agreement with various parties, including representatives of major
consumer groups, related to the implementation of retail electric competition.
On September 23, 1999, the ACC voted to approve the Settlement Agreement, with
some modifications. On December 13, 1999, two parties filed lawsuits challenging
the ACC's approval of the Settlement Agreement. One of the parties questioned
the authority of the ACC to approve the Settlement Agreement and both parties
challenged several specific provisions of the Settlement Agreement. A decision
on the appeals to the Settlement Agreement is not expected until later this year
or next year.
The following are the major provisions of the Settlement Agreement, as approved:
* APS has reduced, and will reduce, rates for standard offer service for
customers with loads less than three MW in a series of annual retail
electric price reductions of 1.5% beginning July 1, 1999 through July
1, 2003, for a total of 7.5%. The first reduction of approximately $24
million ($14 million after income taxes) included the July 1, 1999
retail price decrease of approximately $11 million ($7 million after
income taxes) related to the 1996 regulatory agreement. See "1996
Regulatory Agreement" below. Based on the price reduction authorized
in the Settlement Agreement, there
<PAGE>
-10-
was a retail price decrease of approximately $28 million ($17 million
after taxes), or 1.5%, effective July 1, 2000. For customers having
loads three MW or greater, standard offer rates will be reduced in
varying 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 beginning January 1, 2000,
that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard offer
and unbundled competitive direct access services until July 1, 2004,
except for the price reductions described above and certain other
limited circumstances. Neither the ACC nor 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 MW 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.
* Prior to the Settlement Agreement, APS was 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 against the costs subject to recovery under the
adjustment clause described above.
* APS will form a separate corporate affiliate or affiliates and
transfer to such affiliate(s) its generating assets and competitive
services at book value as of the date of transfer, which transfer
shall take place no later than December 31, 2002.
<PAGE>
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See Management's Discussion and Analysis of Financial Condition and
Results of Operations below for a discussion of the planned timing of
the transfer. APS will be allowed to defer and later collect,
beginning July 1, 2004, 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 it entered into the Settlement
Agreement. To protect APS' rights, it has several lawsuits pending on
ACC orders relating to stranded cost recovery and the adoption and
amendment of the ACC's electric competition rules, which would be
voluntarily dismissed at the appropriate time under this provision.
As discussed in Note 5 above, APS has discontinued the application of SFAS No.
71 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 (Rules). If any of the Rules conflict with the
Settlement Agreement, the terms of the Settlement Agreement govern. On December
8, 1999, APS filed a lawsuit to protect its legal rights regarding the Rules.
This lawsuit is pending, along with several other lawsuits on ACC orders
relating to stranded cost recovery, the adoption or amendment of the Rules and
the certification of competitive electric service providers.
On July 12, 2000, a Maricopa County Superior Court judge issued a preliminary
ruling and denied most of the substantive challenges to the Rules that had been
made by certain electric cooperatives. However, he concluded that some of the
Rules were invalid because of procedural deficiencies or were invalid in their
application. Specifically, the judge concluded that several non-ratemaking Rules
were required to be presented to the Arizona Attorney General for certification
prior to becoming effective. Additionally, the judge determined that the Arizona
Constitution requires the ACC to make findings regarding the fair value of
property in Arizona in establishing rates for competitive electric service
providers (ESPs), which rendered the rate setting provisions of the Rules
invalid in the application.
On November 2, 2000, the same Superior Court judge amended his July 12
preliminary ruling. This amended ruling indicated the Court's intent to accept
the substantive provisions of a form of final judgment submitted by the electric
cooperatives that finds the Rules in their entirety to be unconstitutional and
unlawful due to failure to establish fair value rate base and because certain of
the Rules were not submitted to the Arizona Attorney General for certification.
The cooperatives' proposed form of final judgment also invalidates all the ACC
orders authorizing competitive electric service providers in Arizona. We do not
believe either of the rulings affects the Settlement Agreement with the ACC. The
Settlement Agreement was not at issue in the consolidated cases before the
judge. Further, the ACC made findings related to the fair value of APS' property
in the order approving the APS Settlement Agreement.
<PAGE>
-12-
Although the ACC has not yet indicated what steps it intends to take after a
final judgment is issued, the ACC could appeal the ruling to the Court of
Appeals or could elect to take action to correct the deficiencies identified in
the judge's ruling. The cooperatives or the ESPs may also appeal the ruling. If
the order is appealed by the ACC or any of the ESPs, including APS Energy
Services, we believe that it will be automatically stayed pending further
judicial review.
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 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 MW 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 MW or greater will be eligible for competitive
electric services on the Final Decision Date, which for APS' customers
was the approval of the Settlement Agreement. Customers may also
aggregate smaller loads to meet this one MW requirement.
* Residential customers were phased in at 1.25% per quarter calculated
beginning on January 1, 1999, subject to the 20% requirement above.
* Electric service providers that get Certificates of Convenience and
Necessity (CC&Ns) from the ACC can supply only competitive services,
including electric generation, but not electric transmission and
distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
non-competitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
generation assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the Settlement Agreement, APS
received a waiver to allow transfer of its generation and other
competitive assets and services to affiliates no later than December
31, 2002.
<PAGE>
-13-
See Management's Discussion and Analysis of Financial Condition and
Results of Operations below for a discussion of the planned timing of
the transfer.
1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and APS. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (millions of dollars):
Annual Electric Percentage
Revenue Decrease Decrease Effective Date
---------------- -------- --------------
$49 3.4% July 1, 1996
$18 1.2% July 1, 1997
$17 1.1% July 1, 1998
$11 0.7% July 1, 1999 (a)
(a) Included in the first rate reduction under the Settlement Agreement (see
above).
The regulatory agreement also required the parent company to infuse $200 million
of common equity into APS in annual payments of $50 million from 1996 through
1999. All of these equity infusions were made by December 31, 1999.
LEGISLATION. In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:
* Arizona's largest government-operated electric utility (Salt River Project)
and, at their option, smaller municipal electric systems must (i) make at
least 20% of their 1995 retail peak demand available to electric service
providers by December 31, 1998 and for all retail customers by December 31,
2000; (ii) decrease rates by at least 10% over a ten-year period beginning
as early as January 1, 1991; (iii) implement procedures and public
processes comparable to those already applicable to public service
corporations for establishing the terms, conditions, and pricing of
electric services as well as certain other decisions affecting retail
electric competition;
* describes the factors which form the basis of consideration by Salt River
Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive basis
during the first two years of competition only for customers having demands
in excess of one MW (and that are eligible for competitive generation
services), and thereafter for all customers receiving competitive electric
generation.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, or results of operations. As competition in the
electric industry continues to
<PAGE>
-14-
evolve, we will continue to evaluate strategies and alternatives that will
position the Company and our subsidiaries 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 current congressional session. 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 comprehensive restructuring of the electric utility
industry can occur.
7. Nuclear Insurance
The Palo Verde participants have insurance for public liability payments
resulting from nuclear energy hazards to the full limit of liability under
federal law. This potential liability is covered by primary liability insurance
provided by commercial insurance carriers in the amount of $200 million and the
balance by an industry-wide retrospective assessment program. If losses at any
nuclear power plant covered by the programs exceed the accumulated funds, 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.
<PAGE>
-15-
8. Business Segments
We have two principal business segments (determined by products, services and
regulatory environment) which consist of the transmission and distribution of
electricity and wholesale power marketing and trading activities (delivery
business segment) and the generation of electricity (generation business
segment). The other amounts include activity relating to the parent company and
other subsidiaries including APS Energy Services, SunCor and El Dorado.
Eliminations primarily relate to intersegment sales of electricity. Segment
information for the three, nine and twelve months ended September 30, 2000 and
1999 is as follows (millions of dollars):
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
----------------- ------------------- -------------------
2000 1999 2000 1999 2000 1999
------- ----- ------- ------- ------- -------
Operating Revenues:
<S> <C> <C> <C> <C> <C> <C>
Delivery $ 1,566 $ 867 $ 2,731 $ 1,793 $ 3,231 $ 2,236
Generation 322 266 750 662 942 852
Other 41 27 121 84 167 127
Eliminations (322) (266) (750) (662) (942) (852)
------- ----- ------- ------- ------- -------
Total $ 1,607 $ 894 $ 2,852 $ 1,877 $ 3,398 $ 2,363
======= ===== ======= ======= ======= =======
Income from Continuing Operations:
Delivery $ 57 $ 61 $ 137 $ 115 $ 169 $ 142
Generation 66 69 114 117 117 126
Other (7) (4) 9 (7) 19 (8)
------- ----- ------- ------- ------- -------
Total $ 116 $ 126 $ 260 $ 225 $ 305 $ 260
======= ===== ======= ======= ======= =======
As of September 30, As of December 31,
2000 1999
---- ----
Assets:
Delivery $4,238 $3,796
Generation 2,452 2,342
Other 485 471
------ ------
Total $7,175 $6,609
====== ======
</TABLE>
9. Accounting Matters
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". In June 2000, the FASB issued SFAS No. 138,
which amends certain provisions of SFAS133 to clarify certain areas causing
difficulties in implementation. The amendment includes expanding the normal
purchase and sale exemption for supply contracts. We will adopt SFAS133 and the
corresponding amendments under SFAS138 on
<PAGE>
-16-
January 1, 2001. We are currently determining the impact of SFAS133 on our
consolidated results of operations and financial position; however, certain
implementation issues are currently being resolved by the FASB's Derivatives
Implementation Group that will significantly affect its impact. This statement
should have no impact on consolidated cash flows.
10. Generation Expansion
Pinnacle West Energy has announced plans to build and acquire up to 4,000 MW of
generating capacity from 2001-2006 at an estimated cost of about $2 billion,
assuming all of the announced plants are built or acquired.
Pinnacle West Energy is also considering additional expansion over the next
several years, which may result in additional expenditures. Pinnacle West
Energy's expenditures are expected to be funded through internally generated
cash and debt issued directly by Pinnacle West Energy, as well as capital
infusions from Pinnacle West's internally generated cash and debt proceeds.
Pinnacle West Energy is currently planning a 650-megawatt expansion of the West
Phoenix Power Plant and the construction of a natural gas-fired electric
generating station of up to 2,120 megawatts near Palo Verde, called Redhawk .
Construction on West Phoenix Unit 4 began in June 2000, with commercial
operation of the unit expected in the summer of 2001. Pinnacle West Energy
expects construction to begin on Unit 5 in mid-2001, with commercial operation
in mid- 2003, and expects to partner with Calpine on West Phoenix Unit 5.
Pinnacle West Energy expects that construction will begin on the first two units
of Redhawk near the end of 2000, with commercial operation scheduled for the
summer of 2002.
See "Liquidity and Capital Resources -- Capital Expenditure Requirements" in
Management's Discussion and Analysis of Financial Condition and Results of
Operations below for projected capital expenditures for the above expansion
plans.
On April 27, 2000, Pinnacle West Energy entered into two separate agreements
with SCE to purchase SCE's 15.8% ownership interest in Palo Verde and its 48%
ownership interest in Units 4 and 5 of the Four Corners Power Plant. The
purchase price is $550 million in cash to be paid at closing, subject to certain
adjustments. The interests to be acquired represent 1,310 MW of generating
capacity (600 MW associated with SCE's Palo Verde interest, and 710 MW
associated with SCE's Four Corners interest). The transactions are expected to
close in 2001, subject to the approval of various governmental authorities,
including the CPUC, the FERC, the U.S. Nuclear Regulatory Commission, the
Internal Revenue Service, and the Navajo Nation.
The agreements between Pinnacle West Energy and SCE include the following
additional terms:
* Prior to and up to 90 days following SCE's filing with the CPUC seeking
approval of the transactions, which was made on May 15, 2000, SCE was
allowed to solicit offers for, or indications of interest in, (a) its Four
Corners interest or (b) its Four Corners interest and its Palo Verde
interest. SCE's sale of its interest in Four Corners is also subject to a
right of first refusal on the part of the other Four Corners participants,
including APS. Pinnacle West Energy had the right to match any offer or
indication of interest that SCE
<PAGE>
-17-
received during this period. This period expired without Pinnacle West
Energy matching an indication of interest.
* The Agreements permit SCE, for a period of up to 120 days (until late
November), to engage in further negotiations and discussions with any
party who submitted an indication of interest. Subject to CPUC approval,
Pinnacle West Energy retains the right under the Agreements to match the
terms of any binding agreement that SCE elects to enter into.
* Pinnacle West Energy is not obligated to purchase SCE's Four Corners
interest unless SCE also sells its Palo Verde interest to Pinnacle West
Energy. SCE is not obligated to sell its Palo Verde interest to Pinnacle
West Energy unless Pinnacle West Energy (or some other third party)
purchases SCE's Four Corners interest.
* SCE will transfer the assets of its Palo Verde decommissioning fund to
Pinnacle West Energy, and Pinnacle West Energy will assume SCE's Palo Verde
decommissioning obligations.
* Pinnacle West Energy will assume SCE's obligations and liabilities
associated with ownership of its interests in Palo Verde and Four Corners,
subject to specified exceptions.
* We guaranteed Pinnacle West Energy's obligations under each of the
agreements, including Pinnacle West Energy's purchase price obligations.
The CPUC hearing on approval of the sale has been scheduled for February 2001.
The Utility Reform Network and the Utility Workers Union of America have jointly
filed a motion to dismiss, recommending that the CPUC reject the sale. The
California Office of Ratepayer Advocates has also joined in the motion to
dismiss.
11. Income Tax Benefit
In September 1999, we recorded a tax benefit of $38 million, or $0.45 per basic
or diluted share, which stemmed from the resolution of income tax matters
related to a former subsidiary, MeraBank, A Federal Savings Bank. This amount is
reflected as a tax benefit from discontinued operations in the income statement.
12. El Dorado Partnership Investment Income
Net other income consists primarily of El Dorado's share in the earnings of a
venture capital partnership. The partnership adjusts the value of its
investments at the end of each fiscal quarter. The value of El Dorado's
investment in the partnership is determined by various factors beyond our
control, including equity market conditions. Most of the partnership's
investments are in technology-related companies whose share prices are highly
volatile.
Prior to June 2000, we recorded our share of the earnings from the partnership,
as the partnership adjusted the value of its investment, on a one-quarter lag.
This procedure was followed due to time constraints in obtaining and analyzing
such results for inclusion in our
<PAGE>
-18-
consolidated financial statements on a current basis. Beginning in the second
quarter of 2000, we requested a distribution of our share of the investments
held by the partnership, and we adjusted our investment to reflect the current
market value.
In the third quarter of 2000, we recognized a loss of $9 million after income
taxes, which was our share of the partnership's loss for the quarter. This loss
was the result of a reduction in the market value of the investments held by the
partnership. The book value of El Dorado's investment in the partnership at
September 30, 2000 was approximately $18 million.
El Dorado is currently seeking an amendment to the partnership agreement that
would result in El Dorado receiving a distribution of securities representing
substantially all of El Dorado's investment in the partnership. Upon El Dorado's
receipt of these securities, we will account for the securities as available for
sale with changes in value recorded in other comprehensive income. Gains and
losses from the ultimate sale of such securities will be reflected in our net
earnings.
<PAGE>
-19-
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, Pinnacle
West Energy, APS Energy Services, SunCor, and El Dorado including:
* the changes in our earnings for the periods presented
* the factors impacting our business, including competition
* the effects of regulatory decisions on our results and outlook
* our capital needs and resources and
* our management of market risks.
APS, our major subsidiary and Arizona's largest electric utility, provides
retail and wholesale electric service to the entire state with the exception of
Tucson and about one-half of the Phoenix area. APS also generates, sells, and
delivers electricity to wholesale customers in the western United States. SunCor
is a developer of residential, commercial, and industrial real estate projects
in Arizona, New Mexico, and Utah. El Dorado is primarily a venture capital firm.
APS Energy Services was formed in 1998 and sells energy and energy-related
products and services in competitive retail markets in the western United
States. Pinnacle West Energy, which was formed in 1999, is the subsidiary
through which we intend to conduct our unregulated generation operations.
As discussed in Note 6, the Settlement Agreement and the Rules require APS to
transfer its generating assets and competitive services to one or more corporate
affiliates. We plan to complete the move of our wholesale power marketing and
trading activities from APS to the parent company by the end of 2000. APS plans
to move certain of its non-nuclear generating facilities and related assets, as
well as certain employees of APS' generation business unit, to Pinnacle West
Energy on January 1, 2001, or as soon thereafter as requisite approvals are
obtained. See Note 6 for information regarding lawsuits challenging the
Settlement Agreement and the Rules.
We suggest this section be read along with the 1999 10-K. Throughout this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, we refer to specific "Notes" in the Notes to Condensed Consolidated
Financial Statements in this report. These Notes add further details to the
discussion.
OPERATING RESULTS
The following table summarizes net income for the three-month, nine-month and
twelve-month periods ended September 30, 2000 and the comparable prior year
periods for Pinnacle West and each of its subsidiaries:
<PAGE>
-20-
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
--------------- --------------- ----------------
(Millions of Dollars) 2000 1999 2000 1999 2000 1999(a)
----- ----- ----- ----- ----- -------
<S> <C> <C> <C> <C> <C> <C>
APS $ 124 $ 130 $ 253 $ 232 $ 288 $ 268
Pinnacle West Energy (1) -- (2) -- (2) --
APS Energy Services -- (2) (4) (5) (8) (5)
SunCor 2 -- 8 4 11 7
El Dorado (9) -- 7 -- 18 --
Parent Company -- (2) (2) (6) (2) (9)
----- ----- ----- ----- ----- -----
Income From Continuing Operations 116 126 260 225 305 261
Income Tax Benefit From Discontinued
Operations -- 38 -- 38 -- 38
Extraordinary Charge - Net of Income
Taxes of $94 -- (140) -- (140) -- (140)
----- ----- ----- ----- ----- -----
Net Income $ 116 $ 24 $ 260 $ 123 $ 305 $ 159
===== ===== ===== ===== ===== =====
</TABLE>
(a) SunCor's 1999 earnings have been restated here to exclude a $37 million
deferred tax benefit. In accordance with our intercompany tax sharing
agreement, the offset resides with the parent company. There is no
consolidated earnings effect as these tax benefits had already been
reflected on a consolidated basis.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1999
Consolidated net income for the three months ended September 30, 2000 was $116
million compared with $24 million for the same period in the prior year. The
increase primarily relates to an extraordinary charge recorded in the third
quarter of 1999, partially offset by lower income from continuing operations in
the third quarter of 2000, as well as an income tax benefit from discontinued
operations also recorded in the third quarter of 1999.
The extraordinary charge related to a regulatory disallowance that resulted from
APS' comprehensive Settlement Agreement that was approved by the ACC in
September 1999. See Notes 5 and 6 for additional information about the
regulatory disallowance and the Settlement Agreement.
The income tax benefit from discontinued operations resulted from the resolution
of income tax matters related to a former subsidiary, MeraBank. See Note 11.
Income from continuing operations decreased $10 million over the comparable
prior year period primarily because of a loss at El Dorado, the completion of
the amortization of ITCs in 1999, an electricity price reduction, and
miscellaneous factors. Partially offsetting these factors was an increase in the
contribution of wholesale power marketing and trading activities. See Note 6 for
information on the price reduction. See "Income Taxes" below for a discussion of
the ITC amortization.
Electric operating revenues increased $ 700 million because of:
* increased power marketing, trading, and wholesale revenues ($664
million)
<PAGE>
-21-
* increases in the number of customers and the average amount of
electricity used by customers ($33 million)
* warmer weather impacts ($9 million) and
* miscellaneous factors ($2 million).
As mentioned above, these positive factors were partially offset by the effect
of a reduction in retail electricity prices ($8 million).
The increase in power marketing, trading, and wholesale revenues resulted from
higher prices and increased activity in the western U.S. wholesale power
markets. The revenues were accompanied by an increase in purchased power and
fuel expenses of $602 million.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased prices.
Operations and maintenance expenses increased primarily because of higher costs
related to customer growth.
Property tax expense increased because of higher tax rates.
Depreciation and amortization expense increased primarily because of higher
plant balances.
Net other income and expense decreased $16 million primarily because of a
decrease in the market value of El Dorado's investment in a technology-related
venture capital partnership. See Note 12.
OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1999
Consolidated net income for the nine months ended September 30, 2000 was $260
million compared with $123 million for the same period in the prior year. The
increase primarily relates to an extraordinary charge recorded in the third
quarter of 1999, higher income from continuing operations for the nine months
ended September 30, 2000, partially offset by an income tax benefit from
discontinued operations also recorded in the third quarter of 1999.
The extraordinary charge related to a regulatory disallowance that resulted from
APS' comprehensive Settlement Agreement that was approved by the ACC in
September 1999. See Notes 5 and 6 for additional information about the
regulatory disallowance and the Settlement Agreement.
The income tax benefit from discontinued operations resulted from the resolution
of income tax matters related to a former subsidiary, MeraBank. See Note 11.
Income from continuing operations increased $35 million over the comparable
prior year period primarily because of an increase in the contribution of
wholesale power marketing and trading activities and an increase in El Dorado's
earnings. These positive factors more than offset decreases due to the
completion of the amortization of ITCs in 1999, electricity
<PAGE>
-22-
price reductions, higher operations and maintenance expense, and miscellaneous
factors. See Note 6 for information on the price reductions. See "Income Taxes"
below for a discussion of the ITC amortization.
Electric operating revenues increased $941 million because of:
* increased power marketing, trading, and wholesale revenues ($840
million)
* increases in the number of customers and the average amount of
electricity used by customers ($87 million)
* warmer weather impacts ($28 million) and
* miscellaneous factors ($4 million).
These positive factors were partially offset by the effect of a reduction in
retail electricity prices ($18 million).
The increase in power marketing, trading, and wholesale revenues resulted from
higher prices and increased activity in the western U.S. wholesale power
markets. The revenues were accompanied by an increase in purchased power and
fuel expenses of $734 million.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased prices.
Operations and maintenance expenses increased primarily because of higher costs
primarily related to customer growth.
Net other income and expense increased $15 million primarily because of an
increase in the market value of El Dorado's investment in a technology-related
venture capital partnership. See Note 12.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1999
Consolidated net income for the twelve months ended September 30, 2000 was $305
million compared with $159 million for the same period in the prior year. The
increase primarily relates to an extraordinary charge recorded in the third
quarter of 1999, higher income from continuing operations in the twelve-month
period ended September 30, 2000, partially offset by an income tax benefit from
discontinued operations also recorded in the third quarter of 1999.
The extraordinary charge related to a regulatory disallowance that resulted from
APS' comprehensive Settlement Agreement that was approved by the ACC in
September 1999. See Notes 5 and 6 for additional information about the
regulatory disallowance and the Settlement Agreement.
<PAGE>
-23-
The income tax benefit from discontinued operations resulted from the resolution
of income tax matters related to a former subsidiary, MeraBank. See Note 11.
Income from continuing operations increased $44 million over the comparable
prior year period primarily because of an increase in the contribution of
wholesale power marketing and trading activities, an increase in the number of
customers and in the average amount of electricity used by customers, and an
increase in El Dorado's earnings. These positive factors more than offset
decreases due to the completion of the amortization of ITCs in 1999, reductions
in retail electricity prices, higher operations and maintenance expenses and
miscellaneous factors. See Note 6 for information on the price reduction. See
"Income Taxes" below for a discussion of the ITC amortization.
Electric operating revenues increased $998 million because of:
* increased power marketing, trading, and wholesale revenues ($880
million)
* increases in the number of customers and the average amount of
electricity used by customers ($107 million)
* warmer weather impacts ($35 million) and
* miscellaneous factors ($4 million).
These positive factors were partially offset by the effect of a reduction in
retail prices ($28 million).
The increase in power marketing, trading, and wholesale revenues resulted
primarily from increased activity in western U.S. wholesale power markets and
higher prices. The revenues were accompanied by increases in purchased power and
fuel expenses of $769 million.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased prices.
Operations and maintenance expenses increased primarily because of customer
growth, power marketing costs, and technology related costs.
Net other income and expense increased $29 million primarily because of an
increase in the market value of El Dorado's investment in a technology-related
venture capital partnership. See Note 12.
INCOME TAXES
As part of a 1994 rate settlement with the ACC, APS accelerated amortization of
substantially all deferred ITCs over a five-year period that ended on December
31, 1999. The ITC amortization decreased 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.
<PAGE>
-24-
Liquidity and Capital Resources
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the
nine-month period ended September 30, 2000 and estimated capital expenditures
for the next three years:
CAPITAL EXPENDITURES
(millions of dollars)
Nine months ended Twelve months ended
September 30, 2000 December 31,
(actual) (estimated)(a)
------------------ --------------------------
2000 2001 2002
---- ---- ----
APS (b) $275 $464 $356 $364
Pinnacle West Energy (c) 118 195 544 122
SunCor 42 53 43 51
---- ---- ---- ----
Total $435 $712 $943 $537
==== ==== ==== ====
(a) Includes approximately $40 - $50 million for capital improvements to
existing fossil generating facilities in APS for 2000 and approximately $40
- $50 million in capital improvements to existing fossil generating
facilities in Pinnacle West Energy for each year thereafter.
(b) Includes about $30 - $35 million each year for nuclear fuel expenditures
and approximately $55 - $60 million each year for capital improvements to
existing nuclear generating facilities.
(c) Excludes the SCE purchase agreements of approximately $550 million in 2001.
See Note 10 and "Capital Resources and Debt Financing - Pinnacle West
Energy" below.
CAPITAL RESOURCES AND DEBT FINANCING
PINNACLE WEST
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 1999 10-K.
During the nine-months ended September 30, 2000, the parent company increased
long-term borrowings by about $65 million.
APS
APS' long-term debt redemption requirements, optional repayments on long-term
debt, and payment obligations on a capitalized lease are: $354 million in 2000;
$252 million in 2001; and $125 million in 2002. During the nine months ended
September 30, 2000, APS redeemed all of its long-term debt requirements for 2000
with cash from operations and short-term borrowings. On August 7, 2000, APS
issued $300 million of its 7 5/8% Notes Due 2005.
<PAGE>
-25-
APS expects to purchase Units 1, 2 and 3 of the West Phoenix Power Plant in
December 2000. These units are currently reflected as a capitalized lease.
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 APS may issue, APS does not expect
any of these provisions to limit its ability to meet its capital requirements.
PINNACLE WEST ENERGY
Pinnacle West Energy has announced plans to build and acquire up to 4,000 MW of
generating capacity from 2001-2006 at an estimated cost of about $2 billion,
assuming all announced plants are built or acquired.
Pinnacle West Energy is also considering additional expansion over the next
several years, which may result in additional expenditures. Pinnacle West
Energy's expenditures are expected to be funded through internally generated
cash and debt issued directly by Pinnacle West Energy, as well as capital
infusions from Pinnacle West's internally generated cash and debt proceeds.
Pinnacle West Energy is currently planning a 650-megawatt expansion of the West
Phoenix Power Plant and the construction of a natural gas-fired electric
generating station of up to 2,120 megawatts near Palo Verde, called Redhawk.
Construction on West Phoenix Unit 4 began in June 2000, with commercial
operation of the unit expected in the summer of 2001. Pinnacle West Energy
expects construction to begin on Unit 5 in mid-2001, with commercial operation
in mid-2003, and expects to partner with Calpine on West Phoenix Unit 5.
Pinnacle West Energy also expects that construction will begin on the first two
units of Redhawk near the end of 2000, with commercial operation scheduled for
the summer of 2002.
See the above table for expected capital expenditures for Pinnacle West Energy's
share of these expansions on the current schedule.
Pinnacle West Energy has signed two separate agreements with SCE to acquire
SCE's interest in the Palo Verde Nuclear Generating Station west of Phoenix and
the Four Corners Power Plant near Farmington, New Mexico. Pursuant to the
agreements, Pinnacle West Energy will acquire SCE's 15.8% interest in the three
unit Palo Verde plant and SCE's 48% interest in Four Corners Units 4 and 5, for
a total of approximately 1,300 MW at both plants. The total purchase price is
$550 million, subject to certain adjustments. The transactions are expected to
close in 2001 following the approval of various governmental authorities,
including the CPUC, the FERC, the U.S. Nuclear Regulatory Commission, the
Internal Revenue Service, and the Navajo Nation.
Prior to and up to 90 days following SCE's filing with the CPUC seeking approval
of the transactions, which was made on May 15, 2000, SCE was allowed to solicit
offers for, or indications of interest in, (a) its Four Corners interest or (b)
its Four Corners interest and its Palo Verde interest. SCE's sale of its
interest in Four Corners is also subject to a right of first refusal on the part
of the other Four Corners participants, including APS. Pinnacle West Energy had
the right to match any offer or indication of interest that SCE received during
this period. This period expired without Pinnacle West Energy matching an
indication of interest. The Agreements permit SCE, for a period of up to 120
days (until
<PAGE>
-26-
late November), to engage in further negotiations and discussions with any party
who submitted an indication of interest. Subject to CPUC approval, Pinnacle West
Energy retains the right under the Agreements to match the terms of any binding
agreement that SCE elects to enter into. For additional information about the
transactions, see Note 10.
SUNCOR
SunCor's capital needs consist primarily of capital expenditures for land
development, retail and office building construction, and home construction.
Capital resources to meet these requirements include funds from operations and
SunCor's own external financings.
FINANCIAL OUTLOOK
This section describes the major factors affecting our financial outlook. See
"Liquidity and Capital Resources" for expected capital expenditures and
financing requirements. See "Operating Results" for a summary of each
subsidiary's earnings for the three-month, nine-month, and twelve-month periods
ended September 30, 2000 and 1999.
The electric industry is restructuring to a competitive, customer-driven
environment from a regulated monopoly structure. See Note 6 for a discussion of
industry restructuring developments and their potential impacts on our financial
outlook. In addition to other issues, APS' Settlement Agreement sets forth
electricity prices for its regulated electricity services and the timing for
customer eligibility to select competitive energy providers.
We have announced plans to expand our electricity generation capacity. See Note
10 and "Liquidity and Capital Resources - Pinnacle West Energy" for details of
the generation expansion program. The planned additional generation is expected
to increase revenues, fuel expenses, operating expenses, and financing costs. We
have not announced the estimated effects of the generation expansion activities
on our financial outlook.
Electric operating revenues are derived from sales of electricity in regulated
retail markets in Arizona, and from competitive retail and wholesale bulk power
markets in the western United States. The revenues are expected to be affected
by electricity sales volumes related to customer mix, customer growth and
average usage per customer, as well as electricity prices and variations in
weather from period to period.
In APS' regulated retail market area, APS will provide electricity services to
standard-offer, full-service customers and to energy delivery customers who have
chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in APS' service territory averaged 3.9% a year for
the three years 1997 through 1999; we currently expect customer growth to
average 3.5% to 4% a year for 2000 through 2002. We currently estimate that
electricity sales in kilowatt-hours will grow 4% to 5% a year in 2000 through
2002, before the effects of weather variations. The customer growth and sales
growth referred to in this paragraph apply to energy delivery customers. As
industry restructuring continues in the regulated market area, we cannot predict
the number of APS' standard offer customers that will switch to unbundled
service.
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Bulk power marketing and trading activities will be affected by electricity
prices and costs of available fuel and purchased power from time to time in the
western United States, as well as competitive market conditions and regulatory
and legislative changes in various state and federal jurisdictions. These
factors have significantly affected our wholesale marketing and trading
activities and their resultant earnings contributions over the last several
years. We cannot predict future contributions from bulk power marketing and
trading activities.
Competitive sales of energy and energy-related products and services are made by
APS Energy Services in western states that have opened to competitive supply.
Such activities are currently not material to our consolidated financial
results; however, we currently expect their contribution to grow modestly over
the next several years.
Fuel and purchased power costs are impacted by our electricity sales volumes,
existing contracts for generation fuel and purchased power, our power plant
performance, prevailing market prices, and our hedging program for managing such
costs.
Operations and maintenance expenses are expected to be affected by sales mix and
volumes, inflation, and other factors.
Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property, changes in regulatory
asset amortization, and our generation expansion program. See Note 5 for the
regulatory asset amortization that is being recorded in 1999 through 2004
pursuant to the Settlement Agreement. See Note 1 of Notes to Consolidated
Financial Statements in the 1999 10-K regarding current depreciation rates.
Taxes other than income taxes consist primarily of property taxes, which are
affected by tax rates and the value of property in service and under
construction. We expect property taxes to grow primarily due to our generation
expansion program and our additions to existing facilities.
Interest expense is affected by the amount of debt outstanding and the interest
rates on that debt. The primary factors affecting borrowing levels in the next
several years are expected to be our generation expansion program and our
internally generated cash flow.
The annual earnings contribution from our real estate subsidiary, SunCor, is
expected to increase modestly over the next several years. SunCor's earnings for
1997, 1998 and 1999 were $5.3 million, $7.5 million (excluding the effects of a
deferred tax asset transfer), and $6.1 million, respectively.
El Dorado, our investment subsidiary, is affected by market conditions related
to its investments. See Note 12 for a discussion of recent events affecting El
Dorado's financial results and its outlook. Historical results are not
necessarily indicative of future performance for El Dorado.
Our financial results may be affected by a number of broad factors. See
"Forward-Looking Statements" for further information on such factors, which may
cause our actual future results to differ from those we currently seek or
anticipate.
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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 and to Arizona and federal legal and regulatory
developments.
RATE MATTERS
See Note 6 for a discussion of a price reduction effective as of July 1, 2000,
and for a discussion of a Settlement Agreement that will, among other things,
result in five annual price reductions over a four-year period ending July 1,
2003.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax, and environmental
legislation; our ability to successfully compete outside traditional regulated
markets; regional economic conditions, which could affect customer growth; the
cost of debt and equity capital; weather variations affecting customer usage;
technological developments in the electric industry; the successful completion
of large-scale construction projects; the value of El Dorado's investment in a
technology-related venture capital partnership; successfully managing market
risks; 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 commodity
prices, interest rates, and investments held by the nuclear decommissioning
trust fund.
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage our risks associated with
these market fluctuations by utilizing various
<PAGE>
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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 to hedge
purchases and sales of electricity, fuels and emissions allowances/credits. In
addition, we engage in trading activities intended to profit from favorable
movements of market prices.
As of September 30, 2000, a hypothetical adverse price movement of 10% in the
market price of our commodity derivative portfolio would decrease the fair
market value of these contracts by approximately $37 million. This analysis does
not include the favorable impact this same hypothetical price move would have on
the underlying physical exposures being hedged with the commodity derivative
portfolio. We plan to move our wholesale power marketing and trading activities
from APS to the parent company by the end of 2000.
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. Despite the fact that the great majority
of our trading counterparties are rated as investment grade by the credit rating
agencies, there is still a possibility that one or more of these companies could
default, resulting in a material impact on earnings for a given period.
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-rate and
floating-rate debt. The nuclear decommissioning fund also has risks associated
with changing market values of equity investments. Nuclear decommissioning costs
are recovered in regulated electricity prices.
<PAGE>
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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
Purported Navajo Environmental Regulation
As previously reported, on June 29, 2000, at the request of the Court, APS filed
a motion to dismiss Four Corners from a Petition for Review of EPA's regulations
on the grounds that the impact of the regulations on pre-existing binding
agreements was not "ripe" for judicial resolution based on EPA's issuance of an
official notice indicating that it had not yet determined whether the
pre-existing binding agreements with Four Corners and NGS were abrogated by the
Clean Air Act. See "Environmental Matters--Purported Navajo Environmental
Regulation" in Part II, Item 5 of the June 10-Q. The Court recently dismissed
Four Corners on the above-mentioned grounds.
WATER SUPPLY
As previously reported, APS and other parties petitioned the U.S. Supreme Court
for review of an Arizona Supreme Court decision regarding groundwater rights,
and an issue important to the claims to water in the Lower Gila River Watershed
in Arizona was pending on appeal before the Arizona Supreme Court. See
"Environmental Matters - Water Supply" in Part I - Item 1 of the 1999 10-K. The
U.S. Supreme Court denied the petition. In addition, the Arizona Supreme Court
issued a decision affirming the lower court's definition of groundwater. APS and
other parties have filed a motion for reconsideration on one aspect of that
decision.
PURCHASED POWER AGREEMENTS
As previously reported, in July 2000 APS and PacifiCorp became involved in a
dispute relating to certain provisions of the Long-Term Power Transaction
Agreement dated September 1990. See "Purchased Power Agreements" in Part II,
Item 5 of the June 10-Q. APS and PacifiCorp have settled the issues related to
the dispute. The resolution of this matter will not have a material adverse
impact on our financial position or results of operations.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
10.1 Addendum to Settlement Agreement
27.1 Financial Data Schedule
In addition to those Exhibits shown above, the Company hereby incorporates
the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation
ss.229.10(d) by reference to the filings set forth below:
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO(a) DATE EFFECTIVE
----------- ----------- ---------------------------- ---------- --------------
<S> <C> <C> <C> <C>
10.1 Articles of Incorporation 19.1 to the Company's 1-8962 11-14-88
restated as of July 29, 1988 September 30, 1988
Form 10-Q Report
10.2 Bylaws, amended as of 4.1 to the Company's 1-8962 1-20-00
December 15, 1999 Registration Statement
on Form S-8 No. 333-95035
</TABLE>
(b) Reports on Form 8-K
During the quarter ended September 30, 2000, and the period from October 1
through November 14, 2000, we filed the following reports on Form 8-K:
Report dated July 12, 2000, relating to a preliminary ruling issued by a
Maricopa County Superior Court judge on cross-motions for summary judgment in
connection with lawsuits filed relating to the adoption or amendment of the
retail electric competition rules.
Report dated October 26, 2000, regarding the written materials presented at
an analyst conference in Phoenix, Arizona.
----------
(a) Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Company has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Dated: November 14, 2000 By: Chris N. Froggatt
------------------------------------
Chris N. Froggatt
Vice President and Controller
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)
