PINNACLE WEST CAPITAL CORP, 10-Q filed on 11/1/2011
Quarterly Report
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data
3 Months Ended
Sep. 30,
9 Months Ended
Sep. 30,
2011
2010
2011
2010
OPERATING REVENUES
 
 
 
 
Regulated electricity
$ 1,124,049 
$ 1,116,211 
$ 2,570,692 
$ 2,527,052 
Other revenues
792 
499 
2,795 
4,715 
Total
1,124,841 
1,116,710 
2,573,487 
2,531,767 
OPERATING EXPENSES
 
 
 
 
Regulated electricity fuel and purchased power
337,896 
353,904 
793,952 
821,244 
Operations and maintenance
210,035 
219,658 
675,654 
639,580 
Depreciation and amortization
106,350 
104,177 
319,550 
307,806 
Taxes other than income taxes
34,223 
37,528 
112,002 
100,933 
Other expenses
1,320 
1,169 
4,536 
3,572 
Total
689,824 
716,436 
1,905,694 
1,873,135 
OPERATING INCOME
435,017 
400,274 
667,793 
658,632 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
7,378 
5,524 
18,697 
16,417 
Other income (Note 11)
441 
4,261 
2,630 
3,851 
Other expense (Note 11)
(3,052)
(3,894)
(7,921)
(8,768)
Total
4,767 
5,891 
13,406 
11,500 
INTEREST EXPENSE
 
 
 
 
Interest charges
62,034 
60,419 
183,251 
181,937 
Allowance for borrowed funds used during construction
(6,939)
(6,163)
(14,371)
(12,254)
Total
55,095 
54,256 
168,880 
169,683 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
384,689 
351,909 
512,319 
500,449 
INCOME TAXES
131,416 
122,347 
176,229 
165,882 
INCOME FROM CONTINUING OPERATIONS
253,273 
229,562 
336,090 
334,567 
INCOME FROM DISCONTINUED OPERATIONS
 
 
 
 
Net of income tax expense of $6,216 and $5,859 for three months ended September 30, 2011 and 2010, $7,121 and $14,873 for nine months ended September 30, 2011 and 2010 (Note 13)
9,512 
9,477 
10,860 
23,141 
NET INCOME
262,785 
239,039 
346,950 
357,708 
Less: Net income attributable to noncontrolling interests (Note 7)
7,426 
5,119 
20,041 
15,005 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
255,359 
233,920 
326,909 
342,703 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
109,128 
108,632 
109,003 
105,846 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
109,861 
109,094 
109,683 
106,318 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Income from continuing operations attributable to common shareholders - basic (in dollars per share)
$ 2.25 
$ 2.07 
$ 2.90 
$ 3.02 
Net income attributable to common shareholders - basic (in dollars per share)
$ 2.34 
$ 2.15 
$ 3 
$ 3.24 
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)
$ 2.24 
$ 2.06 
$ 2.88 
$ 3.01 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 2.32 
$ 2.14 
$ 2.98 
$ 3.22 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
 
 
$ 1.575 
$ 1.575 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
 
 
Income from continuing operations, net of tax
245,838 
224,434 
316,001 
319,533 
Discontinued operations, net of tax
9,521 
9,486 
10,908 
23,170 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 255,359 
$ 233,920 
$ 326,909 
$ 342,703 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands
3 Months Ended
Sep. 30,
9 Months Ended
Sep. 30,
2011
2010
2011
2010
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
 
 
Income tax expense on discontinued operations
$ 6,216 
$ 5,859 
$ 7,121 
$ 14,873 
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands
Sep. 30, 2011
Dec. 31, 2010
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 564,712 
$ 110,188 
Customer and other receivables
365,868 
324,207 
Accrued unbilled revenues
184,169 
103,292 
Allowance for doubtful accounts
(4,126)
(7,981)
Materials and supplies (at average cost)
203,118 
181,414 
Fossil fuel (at average cost)
25,403 
21,575 
Deferred income taxes
107,732 
124,897 
Income tax receivable (Note 6)
 
2,483 
Assets from risk management activities (Note 8)
27,713 
73,788 
Deferred fuel and purchased power regulatory asset (Note 3)
31,611 
 
Other regulatory assets (Note 3)
55,852 
62,286 
Other current assets
29,183 
28,362 
Total current assets
1,591,235 
1,024,511 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 8)
32,316 
39,032 
Nuclear decommissioning trust (Note 17)
488,551 
469,886 
Other assets
63,731 
116,216 
Total investments and other assets
584,598 
625,134 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
13,423,406 
13,201,960 
Accumulated depreciation and amortization
(4,684,760)
(4,514,204)
Net
8,738,646 
8,687,756 
Construction work in progress
618,728 
459,361 
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)
133,832 
137,956 
Intangible assets, net of accumulated amortization
176,401 
184,952 
Nuclear fuel, net of accumulated amortization
134,232 
108,794 
Total property, plant and equipment
9,801,839 
9,578,819 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
977,975 
986,370 
Income tax receivable (Note 6)
68,201 
65,103 
Other
126,515 
113,061 
Total deferred debits
1,172,691 
1,164,534 
TOTAL ASSETS
13,150,363 
12,392,998 
CURRENT LIABILITIES
 
 
Accounts payable
281,647 
236,354 
Accrued taxes (Note 6)
191,507 
104,711 
Accrued interest
56,174 
54,831 
Short-term borrowings
 
16,600 
Current maturities of long-term debt
876,363 
631,879 
Customer deposits
71,772 
68,322 
Liabilities from risk management activities (Note 8)
60,667 
58,976 
Deferred fuel and purchased power regulatory liability (Note 3)
 
58,442 
Other regulatory liabilities (Note 3)
94,374 
80,526 
Other current liabilities
150,764 
139,063 
Total current liabilities
1,783,268 
1,449,704 
LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
Long-term debt less current maturities
2,963,457 
2,948,991 
Palo Verde sale leaseback lessor notes less current maturities (Note 7)
83,130 
96,803 
Total long-term debt less current maturities
3,046,587 
3,045,794 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
1,955,458 
1,863,861 
Regulatory liabilities (Note 3)
689,120 
614,063 
Liability for asset retirements (Note 15)
258,332 
328,571 
Liabilities for pension and other postretirement benefits (Note 4)
877,485 
813,121 
Liabilities from risk management activities (Note 8)
58,745 
65,390 
Customer advances
112,730 
121,645 
Coal mine reclamation
117,779 
117,243 
Unrecognized tax benefits (Note 6)
76,936 
66,349 
Other
170,928 
132,031 
Total deferred credits and other
4,317,513 
4,122,274 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
 
 
EQUITY (Note 9)
 
 
Common stock, no par value
2,441,621 
2,421,372 
Treasury stock
(5,232)
(2,239)
Total common stock
2,436,389 
2,419,133 
Retained earnings
1,579,240 
1,423,961 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(56,582)
(59,420)
Derivative instruments
(64,962)
(100,347)
Total accumulated other comprehensive loss
(121,544)
(159,767)
Total shareholders' equity
3,894,085 
3,683,327 
Noncontrolling interests (Note 7)
108,910 
91,899 
Total equity
4,002,995 
3,775,226 
TOTAL LIABILITIES AND EQUITY
$ 13,150,363 
$ 12,392,998 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands
9 Months Ended
Sep. 30,
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 346,950 
$ 357,708 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Gain on sale of district cooling business
 
(41,973)
Gain on sale of energy-related products and services business
(10,404)
 
Depreciation and amortization including nuclear fuel
370,107 
350,762 
Deferred fuel and purchased power
30,965 
50,020 
Deferred fuel and purchased power amortization
(121,018)
(95,926)
Allowance for equity funds used during construction
(18,697)
(16,417)
Real estate impairment charges
 
16,731 
Gain on real estate debt restructuring
 
(14,403)
Deferred income taxes
131,582 
281,486 
Change in mark-to-market valuations
1,861 
3,716 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(47,410)
(103,973)
Accrued unbilled revenues
(80,877)
(69,035)
Materials, supplies and fossil fuel
(25,532)
19,011 
Other current assets
(1,581)
(6,027)
Accounts payable
29,340 
36,687 
Accrued taxes and income tax receivable-net
89,534 
56,851 
Other current liabilities
30,300 
6,738 
Change in margin and collateral accounts - assets
33,591 
(4,336)
Change in margin and collateral accounts - liabilities
85,785 
(143,725)
Change in unrecognized tax benefits
12,123 
(72,649)
Change in other long-term assets
(10,678)
(59,382)
Change in other long-term liabilities
74,565 
17,636 
Net cash flow provided by operating activities
920,506 
569,500 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(643,261)
(552,707)
Contributions in aid of construction
36,351 
25,258 
Allowance for borrowed funds used during construction
(14,371)
(12,553)
Proceeds from sale of district cooling business
 
100,300 
Proceeds from sale of energy-related products and services business
45,111 
 
Proceeds from nuclear decommissioning trust sales
405,637 
424,255 
Investment in nuclear decommissioning trust
(417,957)
(442,567)
Proceeds from sale of commercial real estate investments
1,100 
71,174 
Proceeds from sale of life insurance policies
55,444 
 
Other
(2,346)
9,621 
Net cash flow used for investing activities
(534,292)
(377,219)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
470,353 
 
Repayment of long-term debt
(228,457)
(84,529)
Short-term borrowings and payments - net
(16,600)
(153,715)
Dividends paid on common stock
(166,197)
(161,722)
Common stock equity issuance
14,953 
255,156 
Distributions to noncontrolling interests
(2,610)
(3,286)
Other
(3,132)
6,352 
Net cash flow provided by (used for) financing activities
68,310 
(141,744)
NET INCREASE IN CASH AND CASH EQUIVALENTS
454,524 
50,537 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
110,188 
145,378 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
564,712 
195,915 
Cash paid during the period for:
 
 
Income taxes, net of (refunds)
5,676 
(22,165)
Interest, net of amounts capitalized
$ 163,250 
$ 167,576 
Consolidation and Nature of Operations
Consolidation and Nature of Operations

1.                                      Consolidation and Nature of Operations

 

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor Development Company (“SunCor”), APS Energy Services Company, Inc. (“APSES”), and El Dorado Investment Company (“El Dorado”).  See Note 13 for discussion of discontinued operations of APSES.  Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station (“Palo Verde”) sale leaseback variable interest entities (“VIEs”) (see Note 7 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

 

Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

 

In preparing the condensed consolidated financial statements, we have evaluated the events that have occurred after September 30, 2011 through the date the financial statements were issued.

 

Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.  These condensed consolidated financial statements and notes have been prepared consistently with the 2010 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income, Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows in accordance with accounting requirements for reporting discontinued operations (see Note 13) and the impacts related to the reclassification of regulatory assets and liabilities for the current portion (see Note 3).

 

The following tables show the impact of the reclassifications to prior year (previously reported) amounts (dollars in thousands):

 

Statement of Income for the Three
Months Ended September 30, 2010

 

As
previously
reported

 

Reclassifications
for discontinued
operations

 

Amount
reported after
reclassification
for discontinued
operations

 

Operating Revenues

 

 

 

 

 

 

 

Other revenues

 

$

22,874

 

$

(22,375

)

$

499

 

Operating Expenses

 

 

 

 

 

 

 

Operations and maintenance

 

221,469

 

(1,811

)

219,658

 

Depreciation and amortization

 

104,194

 

(17

)

104,177

 

Other expenses

 

18,365

 

(17,196

)

1,169

 

Other

 

 

 

 

 

 

 

Other income

 

4,348

 

(87

)

4,261

 

Other expense

 

(3,855

)

(39

)

(3,894

)

Interest Expense

 

 

 

 

 

 

 

Interest charges

 

60,491

 

(72

)

60,419

 

Income Taxes

 

123,486

 

(1,139

)

122,347

 

Income From Continuing Operations

 

231,828

 

(2,266

)

229,562

 

Income From Discontinued Operations

 

7,211

 

2,266

 

9,477

 

 

Statement of Income for the Nine
Months Ended September 30, 2010

 

As
previously
reported

 

Reclassifications
for discontinued
operations

 

Amount
reported after
reclassification
for discontinued
operations

 

Operating Revenues

 

 

 

 

 

 

 

Other revenues

 

$

52,982

 

$

(48,267

)

$

4,715

 

Operating Expenses

 

 

 

 

 

 

 

Operations and maintenance

 

644,415

 

(4,835

)

639,580

 

Depreciation and amortization

 

307,864

 

(58

)

307,806

 

Taxes other than income taxes

 

100,936

 

(3

)

100,933

 

Other expenses

 

41,009

 

(37,437

)

3,572

 

Other

 

 

 

 

 

 

 

Other income

 

3,828

 

23

 

3,851

 

Other expense

 

(8,650

)

(118

)

(8,768

)

Interest Expense

 

 

 

 

 

 

 

Allowance for borrowed funds used during construction

 

(12,314

)

60

 

(12,254

)

Income Taxes

 

168,143

 

(2,261

)

165,882

 

Income From Continuing Operations

 

338,395

 

(3,828

)

334,567

 

Income From Discontinued Operations

 

19,313

 

3,828

 

23,141

 

 

Balance Sheets - December 31, 2010

 

As
previously
reported

 

Reclassifications
for regulatory
assets and
liabilities

 

Amount
reported after
reclassification
for regulatory
assets and
liabilities

 

 

 

 

 

 

 

 

 

Current Assets — Deferred income taxes

 

$

94,602

 

$

30,295

 

$

124,897

 

Current Assets — Other regulatory assets

 

 

62,286

 

62,286

 

Deferred Debits — Regulatory assets

 

1,048,656

 

(62,286

)

986,370

 

Current Liabilities — Deferred fuel and purchased power regulatory liability

 

 

58,442

 

58,442

 

Current Liabilities — Other regulatory liabilities

 

 

80,526

 

80,526

 

Deferred Credits and Other — Deferred income taxes

 

1,833,566

 

30,295

 

1,863,861

 

Deferred Credits and Other — Deferred fuel and purchased power regulatory liability

 

58,442

 

(58,442

)

 

Deferred Credits and Other —Regulatory liabilities

 

694,589

 

(80,526

)

614,063

 

 

Statement of Cash Flows for the
Nine Months Ended September 30,
2010

 

As
previously
reported

 

Reclassifications
for regulatory
assets and
liabilities and to
conform to
current year
presentation

 

Amount
reported after
reclassification
for regulatory
assets and
liabilities and to
conform to
current year
presentation

 

Cash Flows from Operating Activities

 

 

 

 

 

 

 

 

 

 

Other current assets

 

$

(13,236

)

$

7,209

 

$

(6,027

)

Other current liabilities

 

10,989

 

(4,251

)

6,738

 

Expenditures for real estate investments

 

(514

)

514

 

 

Gains and other changes in real estate assets

 

1,811

 

(1,811

)

 

Change in other regulatory liabilities

 

40,121

 

(40,121

)

 

Change in other long-term assets

 

(51,659

)

(7,723

)

(59,382

)

Change in other long-term liabilities

 

(28,547

)

46,183

 

17,636

Long-Term Debt and Liquidity Matters
Long-Term Debt and Liquidity Matters

2.                                      Long-Term Debt and Liquidity Matters

 

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

 

Pinnacle West

 

On February 23, 2011, Pinnacle West entered into a $175 million term-loan facility that matures February 20, 2015.  Pinnacle West used the proceeds of the loan to repay its 5.91% $175 million Senior Notes.  Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings or, if unavailable, its long-term issuer ratings.  Through September 30, 2011, Pinnacle West has repaid $40 million of the $175 million term loan facility.

 

At September 30, 2011, Pinnacle West’s $200 million credit facility, which matures in February 2013, was available for bank borrowings, support of its $200 million commercial paper program, or for issuances of letters of credit.  At September 30, 2011, Pinnacle West had no outstanding borrowings or letters of credit under this credit facility and no outstanding commercial paper borrowings.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.

 

APS

 

On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, with a new $500 million facility.  The new revolving credit facility terminates in February 2015.  APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS uses the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit, as necessary from time to time.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

On August 25, 2011, APS issued $300 million of 5.05% unsecured senior notes that mature on September 1, 2041. The net proceeds from the sale of the notes were used along with cash on hand to repay at maturity APS’s $400 million aggregate principal amount of 6.375% senior notes due October 15, 2011.

 

On September 7, 2011, APS entered into a new letter of credit agreement supporting its approximately $27 million aggregate principal amount of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B. The agreement expires September 22, 2016.

 

At September 30, 2011, APS had two credit facilities totaling $1 billion, including the $500 million credit facility described above and a $500 million facility that matures in February 2013.  These facilities are available to support its $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At September 30, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper.  A $20 million letter of credit was outstanding under APS’s 2011 $500 million credit facility described above.

 

See “Financial Assurances” in Note 10 for discussion of APS’s other letters of credit.

 

Debt Fair Value

 

Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 

 

 

As of
September 30, 2011

 

As of
December 31, 2010

 

 

 

Carrying
Amount

 

Fair Value

 

Carrying
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Pinnacle West

 

$

135

 

$

135

 

$

175

 

$

176

 

APS

 

3,788

 

4,219

 

3,503

 

3,737

 

Total

 

$

3,923

 

$

4,354

 

$

3,678

 

$

3,913

 

 

Debt Provisions

 

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At September 30, 2011, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.0 billion, and total capitalization was approximately $7.7 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.1 billion, assuming APS’s total capitalization remains the same. Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

Regulatory Matters
Regulatory Matters

3.                                      Regulatory Matters

 

Retail Rate Case Filing with the Arizona Corporation Commission

 

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  The Company requested that the increase become effective July 1, 2012.  The request would increase the average retail customer bill approximately 6.6%.  The filing is based on a test year ended December 31, 2010, adjusted as described below.  APS’s filing was deemed sufficient by the ACC staff and a hearing has been scheduled to begin January 19, 2012.

 

The key financial provisions of the request included:

 

·                                          an increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through the Company’s renewable energy surcharge (which will increase base rates) and $143.5 million of lower fuel and purchased power costs currently addressed through the Power Supply Adjustor (the “PSA”) (which will decrease base rates);

 

·                                          a rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;

 

·                                          the following proposed capital structure and costs of capital:

 

 

 

Capital Structure

 

Cost of Capital

 

Long-term debt

 

46.1

%

6.38

%

Common stock equity

 

53.9

%

11.00

%

Weighted-average cost of capital

 

 

 

8.87

%

 

·                                          a base rate for fuel and purchased power costs (“Base Fuel Rate”) of $0.03242 per kilowatt-hour (“kWh”) based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).

 

The Company proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision.  In addition, APS proposed two new recovery mechanisms that would adjust electricity rates annually between changes in retail base rates.  The Efficiency and Infrastructure Account, a decoupling mechanism, would address recovery of the Company’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.  The Environmental and Reliability Account, a generation infrastructure adjustment mechanism, would allow recovery of the costs associated with generation investments related to new generation additions, generation efficiency projects and environmental compliance requirements.

 

2008 General Retail Rate Case Impacts

 

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008.  The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates.  The new rates were effective January 1, 2010.  The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:

 

·                                          Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);

 

·                                          An authorized return on common equity of 11%;

 

·                                          A capital structure comprised of 46.2% debt and 53.8% common equity;

 

·                                          A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);

 

·                                          Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and

 

·                                          Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.

 

Cost Recovery Mechanisms

 

APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

 

Renewable Energy Standard.  In 2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (“RES”).  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

 

During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval.  The plan provided for the acquisition of renewable generation in compliance with requirements through 2014, and requested RES funding of $87 million for 2010, which was later approved by the ACC.  APS also sought various other determinations in its plan, including approval of the AZ Sun Program and the Community Power Project in Flagstaff, Arizona described below.

 

On March 3, 2010, the ACC approved the AZ Sun Program, which contemplates the addition of 100 megawatts (“MW”) of APS-owned solar resources through 2014.  Through this program, APS plans to invest up to $500 million in solar photovoltaic projects across Arizona, which APS will acquire through competitive procurement processes.  The costs associated with the first 50 MW under this program will be recovered initially through the RES until such time as the costs are recovered in base rates or other mechanisms.  The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’s current retail rate case, although APS seeks to recover 19 MW of this second tranche in its 2012 RES implementation plan as discussed below.

 

On April 1, 2010, the ACC approved the Community Power Project, a pilot program in which APS will own, operate and receive energy from approximately 1.5 MW of solar panels on the rooftops of up to 200 residential and business customers located within a certain test area in Flagstaff, Arizona.  The capital carrying costs of the program will be recovered through the RES until such time as these costs are recovered in base rates.

 

On July 1, 2010, APS filed its annual RES implementation plan, covering the 2011-2015 timeframe and requesting 2011 RES funding of $96 million.  The 2011 Plan addressed enhancements to the residential distributed energy incentive program based on high customer participation, among other things.  On October 13, 2010, APS filed an adjusted RES implementation plan to reflect the following items, among others: 1) increased clarity relating to customer project in-service dates and related budget revisions; 2) AZ Sun Program updates; and 3) the addition of 10 MW of biomass capacity.  On December 10, 2010, the ACC approved the 2011 Plan and associated funding request.  On February 11, 2011, the ACC amended its original decision that approved the 2011 Plan as follows:  the ACC (a) reversed its approval of a feed-in tariff program; (b) restricted APS’s ownership of facilities to only economically challenged, rural schools and only after a school has received a bid from a third-party solar installer; (c) approved the Rapid Reservation program; and (d) maintained the original approved budget with some timing modifications.

 

On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016  timeframe and requesting 2012 RES funding of $129 million to $152 million.  The range in the funding request arises from APS offering several options for third-party initiatives.  The options involve obtaining 150 MW from third-parties entirely through power purchase agreements (“PPAs”) or through a mix of PPAs and non-residential distributed energy programs.  APS also proposed (i) an additional 100 MW of APS-owned AZ Sun projects; (ii) permission to recover costs for a 19 MW AZ Sun project now instead of waiting for a recovery mechanism in APS’s current retail rate case; and (iii) an additional 25 MW of APS-owned systems on school and government facilities.  On October 26, 2011, the ACC staff issued a report recommending an RES budget of $131.7 million, including the addition of 100 MW of APS-owned AZ Sun projects, permission to recover costs for a 19 MW AZ Sun project through the 2012 RES, and an additional 15 MW of APS-owned systems on school and government facilities.  APS expects a decision from the ACC by year end.

 

Demand-Side Management Adjustor Charge (“DSMAC”).  The settlement agreement related to the 2008 retail rate case requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC.  On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan, requesting approval by the ACC of programs and program elements for which APS had estimated a budget in the amount of $50 million for 2010.  APS received ACC approval of all of its proposed programs and implemented the new DSMAC on March 1, 2010.  A surcharge was added to customer bills in order to recover these estimated amounts for use on certain demand-side management programs.  The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.

 

The ACC approved recovery of all 2009 program costs plus incentives.  The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery.  As requested by APS, 2009 program cost recovery is to be amortized over a three-year period.

 

On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million.  On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.

 

On June 1, 2011, APS filed its 2012 Energy Efficiency Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the settlement agreement (1.5% of total energy resources). APS proposed a budget for 2012 of $90 million. When added to the third and final year of the amortization of 2009 program costs discussed above and less the $10 million already being recovered in general rates, the proposed 2012 DSMAC would recover approximately $85 million over a twelve month period beginning March 1, 2012.  APS expects a decision from the ACC by year end.

 

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.

 

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2011 and 2010 (dollars in millions):

 

 

 

Nine Months Ended
September 30,

 

 

 

2011

 

2010

 

Beginning balance

 

$

(58

)

$

(87

)

Deferred fuel and purchased power costs-current period

 

(31

)

(50

)

Amounts refunded through revenues

 

121

 

96

 

Ending balance

 

$

32

 

$

(41

)

 

The PSA rate for the PSA year beginning February 1, 2011 is ($0.0057) per kWh as compared to ($0.0045) per kWh for the prior year.  Any uncollected (overcollected) deferrals during the 2011 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2012.

 

Transmission Rates and Transmission Cost AdjustorIn July 2008, the United States Federal Energy Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”).  In order to recover the Retail Transmission Charges, APS must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the transmission cost adjustor (“TCA”).

 

The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC staff.  Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.

 

Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula.  Approximately $38 million of this revenue increase relates to Retail Transmission Charges.  The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

 

Regulatory Assets and Liabilities

 

As discussed in Note 1, as of September 30, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Condensed Consolidated Balance Sheets.  This presentation is reflected in the tables below.

 

The detail of regulatory assets is as follows (dollars in millions):

 

 

 

September 30, 2011

 

December 31, 2010

 

 

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Pension and other postretirement benefits

 

$

 

$

663

 

$

 

$

669

 

Deferred income taxes

 

3

 

82

 

3

 

69

 

Deferred fuel and purchased power — mark-to-market (Note 8)

 

35

 

27

 

42

 

35

 

Transmission vegetation management

 

9

 

34

 

 

46

 

Coal reclamation

 

2

 

35

 

2

 

36

 

Palo Verde VIE (Note 7)

 

 

34

 

 

33

 

Deferred compensation

 

 

34

 

 

32

 

Deferred fuel and purchased power (a)

 

32

 

 

 

 

Tax expense of Medicare subsidy

 

2

 

18

 

2

 

21

 

Loss on reacquired debt

 

1

 

19

 

1

 

21

 

Pension and other post-retirement benefits deferral

 

 

9

 

 

 

Demand side management (a)

 

3

 

2

 

12

 

6

 

Other

 

 

21

 

 

18

 

Total regulatory assets (b)

 

$

87

 

$

978

 

$

62

 

$

986

 

 

(a)                                  See Cost Recovery Mechanisms discussion above.

(b)                                 There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”

 

The detail of regulatory liabilities is as follows (dollars in millions):

 

 

 

September 30, 2011

 

December 31, 2010

 

 

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Removal costs (a)

 

$

21

 

$

355

 

$

22

 

$

357

 

Asset retirement obligations (Note 15)

 

 

202

 

 

184

 

Renewable energy standard (b)

 

58

 

 

50

 

 

Income taxes — change in rates

 

 

50

 

 

 

Spent nuclear fuel

 

5

 

43

 

4

 

41

 

Deferred gains on utility property

 

2

 

15

 

2

 

16

 

Income taxes- deferred investment tax credit

 

 

9

 

 

1

 

Deferred fuel and purchased power (b)(c)

 

 

 

58

 

 

Other

 

8

 

15

 

3

 

15

 

Total regulatory liabilities

 

$

94

 

$

689

 

$

139

 

$

614

 

 

(a)                                  In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.

(b)                                 See Cost Recovery Mechanisms discussion above.

(c)                                  Subject to a carrying charge.

Retirement Plans and Other Benefits
Retirement Plans and Other Benefits

4.                                      Retirement Plans and Other Benefits

 

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.

 

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates are deferred as a regulatory asset for future recovery, pursuant to an ACC regulatory order.  The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset) (dollars in millions):

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

Three Months
Ended
September 30,

 

Nine Months
Ended
September 30,

 

Three Months
Ended
September 30,

 

Nine Months
Ended
September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Service cost - benefits earned during the period

 

$

14

 

$

14

 

$

43

 

$

42

 

$

5

 

$

4

 

$

17

 

$

14

 

Interest cost on benefit obligation

 

31

 

31

 

94

 

92

 

12

 

11

 

35

 

32

 

Expected return on plan assets

 

(33

)

(31

)

(100

)

(93

)

(10

)

(9

)

(31

)

(29

)

Amortization of:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prior service cost

 

 

 

1

 

1

 

 

 

 

 

Net actuarial loss

 

7

 

5

 

19

 

15

 

4

 

2

 

11

 

7

 

Net periodic benefit cost

 

$

19

 

$

19

 

$

57

 

$

57

 

$

11

 

$

8

 

$

32

 

$

24

 

Portion of cost charged to expense

 

$

7

 

$

10

 

$

22

 

$

29

 

$

4

 

$

4

 

$

12

 

$

12

 

 

Contributions

 

The required minimum contribution to our pension plan is zero in 2011 and approximately $68 million in 2012.  The contributions to our other postretirement benefit plans for 2011 and 2012 are expected to be approximately $20 million each year.

Business Segments
Business Segments

5.                                      Business Segments

 

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and related activities and includes electricity generation, transmission and distribution.

 

Financial data for the three and nine months ended September 30, 2011 and 2010 and at September 30, 2011 and December 31, 2010 is provided as follows (dollars in millions):

 

 

 

Three Months Ended
September 30, 

 

Nine Months Ended
September 30, 

 

 

 

2011

 

2010

 

2011

 

2010

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Regulated electricity segment

 

$

1,124

 

$

1,116

 

$

2,571

 

$

2,527

 

All other

 

1

 

1

 

2

 

5

 

Total

 

$

1,125

 

$

1,117

 

$

2,573

 

$

2,532

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to common shareholders:

 

 

 

 

 

 

 

 

 

Regulated electricity segment

 

$

246

 

$

225

 

$

318

 

$

320

 

All other (a)

 

9

 

9

 

9

 

23

 

Total

 

$

255

 

$

234

 

$

327

 

$

343

 

 

 

 

As of
September 30, 2011

 

As of
December 31, 2010

 

Assets:

 

 

 

 

 

Regulated electricity segment

 

$

13,112

 

$

12,285

 

All other (a)

 

38

 

108

 

Total

 

$

13,150

 

$

12,393

 

 

(a)                                  All other activities relate to APSES, SunCor, Pinnacle West and El Dorado.

Income Taxes
Income Taxes

6.                                      Income Taxes

 

The $68 million income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.  This amount is classified as long-term, as cash refunds are not expected to be received in the next twelve months.

 

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. In the first quarter of 2011, Pinnacle West increased regulatory liabilities by a total of $53 million, with a corresponding decrease in accumulated deferred income tax liabilities to reflect the impact of this change in tax law.

 

As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS.  With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2006.  We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.

Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities

7.                                      Palo Verde Sale Leaseback Variable Interest Entities

 

In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  The VIE lessor trusts are single-asset leasing entities.  APS will pay approximately $49 million per year for the years 2011 to 2015 related to these leases.  The leases do not contain fixed price purchase options or residual value guarantees.  However, the lease agreements include fixed rate renewal periods which may have a significant impact on the VIEs’ economic performance.  We have concluded that these fixed rate renewal periods may give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  In addition to the fixed rate renewal periods, our primary beneficiary analysis also considered that APS is the operating agent for Palo Verde, has fair value purchase options, and is obligated to decommission the leased assets.

 

For the reasons discussed above, APS consolidates these VIEs.  Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders.  Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease.  As a result of consolidation we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three and nine months ended September 30, 2011 of $7 million and of $20 million respectively, entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders remains the same.  Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

 

Our Condensed Consolidated Balance Sheets at September 30, 2011 and December 31, 2010 include the following amounts relating to the VIEs (in millions):

 

 

 

September 30,
2011

 

December 31,
2010 

 

Property plant and equipment, net of accumulated depreciation

 

$

134

 

$

138

 

Current maturities of long-term debt

 

30

 

29

 

Long-term debt less current maturities

 

83

 

97

 

Equity- Noncontrolling interests

 

109

 

91

 

 

For regulatory ratemaking purposes the agreements are treated as operating leases and, as a result, we have recorded a regulatory asset of $34 million as of September 30, 2011 and $33 million as of December 31, 2010.

 

APS is exposed to losses relating to these lessor trust VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of September 30, 2011, APS would have been required to pay the noncontrolling equity participants approximately $145 million and assume $113 million of debt.  Since APS consolidates the VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

Derivative Accounting
Derivative Accounting

8.                                      Derivative Accounting

 

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria are designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, some of these instruments may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Contracts that have the same terms (quantities and delivery points) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

 

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 14 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchase and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

 

Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time.  We assess hedge effectiveness both at inception and on a continuing basis.  These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of accumulated other comprehensive income (“AOCI”) and reclassified into earnings in the same period during which the hedged transaction affects earnings.  We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As of September 30, 2011, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

 

For its regulated operations, APS defers for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

 

As of September 30, 2011, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

 

Commodity

 

Quantity

 

Power

 

11,997

gigawatt hours

 

Gas

 

124,151

billion Btu (a)

 

 

(a)                                  “Btu” is British thermal units.

 

Gains and Losses from Derivative Instruments

 

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and nine months ended September 30, 2011 and 2010 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Commodity Contracts

 

Location

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss Recognized in AOCI (Effective Portion)

 

Accumulated other comprehensive loss-derivative instruments

 

$

(25,457

)

$

(67,856

)

$

(40,792

)

$

(168,110

)

Loss Reclassified from AOCI into Income (Effective Portion Realized)

 

Regulated electricity segment fuel and purchased power

 

(59,144

)

(59,801

)

(99,278

)

(102,130

)

Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a) 

 

Regulated electricity segment fuel and purchased power

 

17

 

(68

)

(147

)

1,364

 

 

(a)                                  During the three and nine months ended September 30, 2011 and 2010, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.

 

During the next twelve months, we estimate that a net loss of $68 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, certain of these amounts will be recorded as either a regulatory asset or liability and have no effect on earnings.

 

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and nine months ended September 30, 2011 and 2010 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Commodity Contracts

 

Location

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Gain Recognized in Income

 

Regulated electricity segment revenue

 

$

81

 

$

1,721

 

$

1,085

 

$

2,316

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Loss Recognized in Income

 

Regulated electricity segment fuel and purchased power expense

 

(13,219

)

(41,044

)

(25,138

)

(105,272

)

Total

 

 

 

$

(13,138

)

$

(39,323

)

$

(24,053

)

$

(102,956

)

 

Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

 

The following table provides information about the fair value of our risk management activities reported on a gross basis.  Transactions with counterparties that have contractual net settlement provisions are reported net on the Condensed Consolidated Balance Sheets.  These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.  Amounts are as of September 30, 2011 (dollars in thousands):

 

Commodity Contracts

 

Designated
as Hedging
Instruments

 

Not
Designated
as Hedging
Instruments

 

Margin and
Collateral
Provided to
Counterparties

 

Collateral
Provided from
Counterparties

 

Other (a)

 

Total

 

Current Assets

 

$

6,608

 

$

64,177

 

$

1,529

 

$

 

$

(44,601

)

$

27,713

 

Investments and Other Assets

 

2,700

 

40,918

 

 

 

(11,302

)

32,316

 

Total Assets

 

9,308

 

105,095

 

1,529

 

 

(55,903

)

60,029

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(61,134

)

(110,437

)

77,002

 

(12,145

)

46,047

 

(60,667

)

Deferred Credits and Other

 

(45,393

)

(65,365

)

40,711

 

 

11,302

 

(58,745

)

Total Liabilities

 

(106,527

)

(175,802

)

117,713

 

(12,145

)

57,349

 

(119,412

)

Total

 

$

(97,219

)

$

(70,707

)

$

119,242

 

$

(12,145

)

$

1,446

 

$

(59,383

)

 

(a)          Other represents derivative instrument netting, options, and other risk management contracts.

 

The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2010 (dollars in thousands):

 

Commodity Contracts

 

Designated
as Hedging
Instruments

 

Not
Designated
as Hedging
Instruments

 

Margin and
Collateral
Provided to
Counterparties

 

Collateral
Provided from
Counterparties

 

Other (a)

 

Total

 

Current Assets

 

$

10,295

 

$

64,153

 

$

36,135

 

$

(1,750

)

$

(35,045

)

$

73,788

 

Investments and Other Assets

 

5,056

 

60,813

 

 

 

(26,837

)

39,032

 

Total Assets

 

15,351

 

124,966

 

36,135

 

(1,750

)

(61,882

)

112,820

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(108,387

)

(112,847

)

126,364

 

(1,250

)

37,144

 

(58,976

)

Deferred Credits and Other

 

(73,041

)

(85,506

)

66,393

 

 

26,764

 

(65,390

)

Total Liabilities

 

(181,428

)

(198,353

)

192,757

 

(1,250

)

63,908

 

(124,366

)

Total

 

$

(166,077

)

$

(73,387

)

$

228,892

 

$

(3,000

)

$

2,026

 

$

(11,546

)

 

(a)          Other represents derivative instrument netting, options, and other risk management contracts.

 

Credit Risk and Credit Related Contingent Features

 

We are exposed to losses in the event of nonperformance or nonpayment by counterparties.  We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 76% of Pinnacle West’s $60 million of risk management assets as of September 30, 2011.  This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties’ debt is 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 consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

 

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.   For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

 

The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2011 (dollars in millions):

 

 

 

September 30,
2011

 

Aggregate Fair Value of Derivative Instruments in a Net Liability Position

 

$

254

 

Cash Collateral Posted

 

99

 

Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)

 

136

 

 

(a)          This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the footnote above.

 

We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features which could also require us to post additional collateral of approximately $194 million if our debt credit ratings were to fall below investment grade.

Changes in Equity
Changes in Equity

9.             Changes in Equity

 

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2011 and 2010 (dollars in thousands):

 

 

 

Three Months Ended September 30, 2011

 

Three Months Ended September 30, 2010

 

 

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, July 1

 

$

3,613,705

 

$

101,905

 

$

3,715,610

 

$

3,479,548

 

$

113,455

 

$

3,593,003

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

255,359

 

7,426

 

262,785

 

233,920

 

5,119

 

239,039

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net unrealized losses on derivative instruments (a)

 

(25,457

)

 

(25,457

)

(67,856

)

 

(67,856

)

Net reclassification of realized losses to income (b)

 

59,144

 

 

59,144

 

59,801

 

 

59,801

 

Reclassification of pension and other postretirement benefits to income

 

1,239

 

 

1,239

 

1,314

 

 

1,314

 

Net income tax benefit (expense) related to items of other comprehensive income (loss)

 

(13,795

)

 

(13,795

)

2,660

 

 

2,660

 

Total other comprehensive income (loss)

 

21,131

 

 

21,131

 

(4,081

)

 

(4,081

)

Total comprehensive income

 

276,490

 

7,426

 

283,916

 

229,839

 

5,119

 

234,958

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

3,789

 

 

3,789

 

2,506

 

 

2,506

 

Purchase of treasury stock, net of reissuances

 

537

 

 

537

 

577

 

 

577

 

Other (primarily stock compensation)

 

(424

)

 

(424

)

4,456

 

 

4,456

 

Dividends on common stock

 

(12

)

 

(12

)

 

 

 

Net capital activities by noncontrolling interests

 

 

(421

)

(421

)

 

(7,271

)

(7,271

)

Ending balance, September 30

 

$

3,894,085

 

$

108,910

 

$

4,002,995

 

$

3,716,926

 

$

111,303

 

$

3,828,229

 

 

 

 

Nine Months Ended September 30, 2011

 

Nine Months Ended September 30, 2010

 

 

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, January 1

 

$

3,683,327

 

$

91,899

 

$

3,775,226

 

$

3,316,109

 

$

111,895

 

$

3,428,004

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

326,909

 

20,041

 

346,950

 

342,703

 

15,005

 

357,708

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net unrealized losses on derivative instruments (a)

 

(40,792

)

 

(40,792

)

(168,110

)

 

(168,110

)

Net reclassification of realized losses to income (b)

 

99,278

 

 

99,278

 

102,130

 

 

102,130

 

Reclassification of pension and other postretirement benefits to income

 

3,718

 

 

3,718

 

4,069

 

 

4,069

 

Net unrealized gains (losses) related to pension and other postretirement benefits

 

974

 

 

974

 

(6,933

)

 

(6,933

)

Net income tax benefit (expense) related to items of other comprehensive income (loss)

 

(24,954

)

 

(24,954

)

27,171

 

 

27,171

 

Total other comprehensive income (loss)

 

38,224

 

 

38,224

 

(41,673

)

 

(41,673

)

Total comprehensive income

 

365,133

 

20,041

 

385,174

 

301,030

 

15,005

 

316,035

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

20,854

 

 

20,854

 

260,665

 

 

260,665

 

Purchase of treasury stock, net of reissuances

 

(2,993

)

 

(2,993

)

1,655

 

 

1,655

 

Other (primarily stock compensation)