PINNACLE WEST CAPITAL CORP, 10-Q filed on 8/2/2011
Quarterly Report
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data
3 Months Ended
Jun. 30,
6 Months Ended
Jun. 30,
2011
2010
2011
2010
OPERATING REVENUES
 
 
 
 
Regulated electricity segment
$ 798,669 
$ 799,416 
$ 1,446,643 
$ 1,410,841 
Other revenues
1,130 
3,379 
2,003 
4,216 
Total
799,799 
802,795 
1,448,646 
1,415,057 
OPERATING EXPENSES
 
 
 
 
Regulated electricity segment fuel and purchased power
244,049 
251,800 
456,056 
467,340 
Operations and maintenance
210,590 
213,609 
465,619 
419,922 
Depreciation and amortization
106,617 
102,995 
213,200 
203,629 
Taxes other than income taxes
40,155 
31,682 
77,779 
63,405 
Other expenses
1,396 
1,325 
3,216 
2,403 
Total
602,807 
601,411 
1,215,870 
1,156,699 
OPERATING INCOME
196,992 
201,384 
232,776 
258,358 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
5,924 
5,504 
11,319 
10,893 
Other income (Note 11)
557 
943 
2,247 
1,892 
Other expense (Note 11)
(3,186)
(5,650)
(4,927)
(7,176)
Total
3,295 
797 
8,639 
5,609 
INTEREST EXPENSE
 
 
 
 
Interest charges
60,140 
60,751 
121,217 
121,518 
Allowance for borrowed funds used during construction
(3,856)
(3,072)
(7,432)
(6,091)
Total
56,284 
57,679 
113,785 
115,427 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
144,003 
144,502 
127,630 
148,540 
INCOME TAXES
50,818 
51,188 
44,813 
43,535 
INCOME FROM CONTINUING OPERATIONS
93,185 
93,314 
82,817 
105,005 
INCOME FROM DISCONTINUED OPERATIONS
 
 
 
 
Net of income tax expense of $773 and $16,922 for three months ended and $906 and $9,013 for six months ended June 30, 2011 and 2010, respectively (Note 13)
654 
26,252 
1,348 
13,664 
NET INCOME
93,839 
119,566 
84,165 
118,669 
Less: Net income attributable to noncontrolling interests (Note 7)
7,154 
4,769 
12,615 
9,886 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
86,685 
114,797 
71,550 
108,783 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
109,044 
107,355 
108,939 
104,431 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
109,718 
107,764 
109,540 
104,857 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Income from continuing operations attributable to common shareholders - basic (in dollars per share)
$ 0.79 
$ 0.82 
$ 0.64 
$ 0.91 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.80 
$ 1.07 
$ 0.66 
$ 1.04 
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)
$ 0.78 
$ 0.82 
$ 0.64 
$ 0.91 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 0.79 
$ 1.07 
$ 0.65 
$ 1.04 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 1.05 
$ 1.05 
$ 1.575 
$ 1.575 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
 
 
Income from continuing operations, net of tax
86,001 
88,536 
70,163 
95,099 
Discontinued operations, net of tax
684 
26,261 
1,387 
13,684 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 86,685 
$ 114,797 
$ 71,550 
$ 108,783 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands
3 Months Ended
Jun. 30,
6 Months Ended
Jun. 30,
2011
2010
2011
2010
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
 
 
Income tax expense on discontinued operations
$ 773 
$ 16,922 
$ 906 
$ 9,013 
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands
Jun. 30, 2011
Dec. 31, 2010
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 92,274 
$ 110,188 
Customer and other receivables
294,532 
324,207 
Accrued unbilled revenues
163,682 
103,292 
Allowance for doubtful accounts
(3,791)
(7,981)
Materials and supplies (at average cost)
194,352 
181,414 
Fossil fuel (at average cost)
26,863 
21,575 
Deferred income taxes
113,243 
124,897 
Assets held for sale
30,540 
2,861 
Income tax receivable (Note 6)
 
2,483 
Assets from risk management activities (Note 8)
38,897 
73,788 
Regulatory assets (Note 3)
56,158 
62,286 
Other current assets
30,103 
25,501 
Total current assets
1,036,853 
1,024,511 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 8)
43,173 
39,032 
Nuclear decommissioning trust (Note 14)
497,671 
469,886 
Other assets
63,726 
116,216 
Total investments and other assets
604,570 
625,134 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
13,351,239 
13,201,960 
Accumulated depreciation and amortization
(4,675,228)
(4,514,204)
Net
8,676,011 
8,687,756 
Construction work in progress
524,870 
459,361 
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)
134,799 
137,956 
Intangible assets, net of accumulated amortization
177,845 
184,952 
Nuclear fuel, net of accumulated amortization
142,697 
108,794 
Total property, plant and equipment
9,656,222 
9,578,819 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
983,394 
986,370 
Income tax receivable (Note 6)
67,970 
65,103 
Other
125,071 
113,061 
Total deferred debits
1,176,435 
1,164,534 
TOTAL ASSETS
12,474,080 
12,392,998 
CURRENT LIABILITIES
 
 
Accounts payable
271,759 
236,354 
Accrued taxes (Note 6)
131,727 
104,711 
Accrued interest
55,123 
54,831 
Common dividends payable
57,272 
 
Short-term borrowings
7,300 
16,600 
Current maturities of long-term debt
903,516 
631,879 
Customer deposits
70,196 
68,322 
Liabilities from risk management activities (Note 8)
58,684 
58,976 
Deferred fuel and purchased power regulatory liability (Note 3)
54,359 
58,442 
Other regulatory liabilities (Note 3)
88,557 
80,526 
Other current liabilities
132,801 
139,063 
Total current liabilities
1,831,294 
1,449,704 
LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
Long-term debt less current maturities
2,678,565 
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
2,761,695 
3,045,794 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
1,825,077 
1,863,861 
Regulatory liabilities (Note 3)
695,036 
614,063 
Liability for asset retirements (Note 15)
255,326 
328,571 
Liabilities for pension and other postretirement benefits (Note 4)
869,277 
813,121 
Liabilities from risk management activities (Note 8)
57,073 
65,390 
Customer advances
120,621 
121,645 
Coal mine reclamation
117,651 
117,243 
Unrecognized tax benefits (Note 6)
83,229 
66,349 
Other
142,191 
132,031 
Total deferred credits and other
4,165,481 
4,122,274 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
 
 
EQUITY (Note 9)
 
 
Common stock, no par value
2,438,256 
2,421,372 
Treasury stock
(5,768)
(2,239)
Total common stock
2,432,488 
2,419,133 
Retained earnings
1,323,892 
1,423,961 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(57,332)
(59,420)
Derivative instruments
(85,343)
(100,347)
Total accumulated other comprehensive loss
(142,675)
(159,767)
Total shareholders' equity
3,613,705 
3,683,327 
Noncontrolling interests (Note 7)
101,905 
91,899 
Total equity
3,715,610 
3,775,226 
TOTAL LIABILITIES AND EQUITY
$ 12,474,080 
$ 12,392,998 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands
6 Months Ended
Jun. 30,
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 84,165 
$ 118,669 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Gain on sale of district cooling business
 
(41,973)
Depreciation and amortization including nuclear fuel
245,700 
229,964 
Deferred fuel and purchased power
64,679 
65,249 
Deferred fuel and purchased power amortization
(68,762)
(55,494)
Allowance for equity funds used during construction
(11,319)
(10,893)
Real estate impairment charges
 
16,731 
Deferred income taxes
11,945 
50,972 
Change in mark-to-market valuations
(279)
2,396 
Changes in current assets and liabilities:
 
 
Customer and other receivables
43,271 
(7,133)
Accrued unbilled revenues
(60,390)
(51,470)
Materials, supplies and fossil fuel
(18,226)
13,577 
Other current assets
(37,053)
(8,340)
Accounts payable
37,817 
45,313 
Accrued taxes and income tax receivable-net
29,530 
75,546 
Other current liabilities
3,967 
(26,583)
Expenditures for real estate investments
(40)
(458)
Gains and other changes in real estate assets
 
(2,931)
Change in margin and collateral accounts - assets
21,185 
656 
Change in margin and collateral accounts - liabilities
39,567 
(90,694)
Change in unrecognized tax benefits
18,959 
(62,630)
Change in other long-term assets
(26,185)
(11,015)
Change in other long-term liabilities
57,748 
(48,045)
Net cash flow provided by operating activities
436,279 
201,414 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(387,272)
(378,579)
Contributions in aid of construction
21,905 
15,163 
Allowance for borrowed funds used during construction
(7,432)
(6,395)
Proceeds from sale of district cooling business
 
100,300 
Proceeds from nuclear decommissioning trust sales
299,600 
329,796 
Investment in nuclear decommissioning trust
(308,222)
(342,004)
Proceeds from sale of life insurance policies
55,444 
 
Other
(2,352)
3,850 
Net cash flow used for investing activities
(328,329)
(277,869)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
175,000 
 
Repayment of long-term debt
(187,962)
(15,221)
Short-term borrowings and payments - net
(9,300)
(149,099)
Dividends paid on common stock
(112,537)
(106,522)
Common stock equity issuance
14,520 
254,612 
Distributions to noncontrolling interests
(2,610)
(3,286)
Other
(2,975)
1,095 
Net cash flow used for financing activities
(125,864)
(18,421)
NET DECREASE IN CASH AND CASH EQUIVALENTS
(17,914)
(94,876)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
110,188 
145,378 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
92,274 
50,502 
Cash paid during the period for:
 
 
Income taxes, net of (refunds)
 
(3,944)
Interest, net of amounts capitalized
$ 110,659 
$ 115,722 
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 June 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 June 30, 2010

 

As
previously
reported

 

Reclassifications
for discontinued
operations

 

Amount
reported after
reclassification
for discontinued
operations

 

Operating Revenues

 

 

 

 

 

 

 

Other revenues

 

$

21,178

 

$

(17,799

)

$

3,379

 

Operating Expenses

 

 

 

 

 

 

 

Operations and maintenance

 

215,104

 

(1,495

)

213,609

 

Depreciation and amortization

 

103,017

 

(22

)

102,995

 

Taxes other than income taxes

 

31,684

 

(2

)

31,682

 

Other expenses

 

15,716

 

(14,391

)

1,325

 

Other

 

 

 

 

 

 

 

Other income

 

933

 

10

 

943

 

Other expense

 

(5,660

)

10

 

(5,650

)

Interest Expense

 

 

 

 

 

 

 

Interest charges

 

60,741

 

10

 

60,751

 

Allowance for borrowed funds used during construction

 

(3,104

)

32

 

(3,072

)

Income Taxes

 

51,829

 

(641

)

51,188

 

Income From Continuing Operations

 

94,584

 

(1,270

)

93,314

 

Income From Discontinued Operations

 

24,982

 

1,270

 

26,252

 

 

Statement of Income for the Six
Months Ended June 30, 2010

 

As
previously
reported

 

Reclassifications
for discontinued
operations

 

Amount
reported after
reclassification
for discontinued
operations

 

Operating Revenues

 

 

 

 

 

 

 

Other revenues

 

$

30,108

 

$

(25,892

)

$

4,216

 

Operating Expenses

 

 

 

 

 

 

 

Operations and maintenance

 

422,946

 

(3,024

)

419,922

 

Depreciation and amortization

 

203,670

 

(41

)

203,629

 

Taxes other than income taxes

 

63,408

 

(3

)

63,405

 

Other expenses

 

22,644

 

(20,241

)

2,403

 

Other

 

 

 

 

 

 

 

Other income

 

1,819

 

73

 

1,892

 

Other expense

 

(7,134

)

(42

)

(7,176

)

Interest Expense

 

 

 

 

 

 

 

Interest charges

 

121,446

 

72

 

121,518

 

Allowance for borrowed funds used during construction

 

(6,151

)

60

 

(6,091

)

Income Taxes

 

44,657

 

(1,122

)

43,535

 

Income From Continuing Operations

 

106,567

 

(1,562

)

105,005

 

Income From Discontinued Operations

 

12,102

 

1,562

 

13,664

 

 

Balance Sheets - December 31, 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

 

 

 

 

 

 

 

 

 

Current Assets — Regulatory assets

 

$

 

$

62,286

 

$

62,286

 

Current Assets — Deferred income taxes

 

94,602

 

30,295

 

124,897

 

Current Assets — Assets held for sale

 

 

2,861

 

2,861

 

Current Assets — Other current assets

 

28,362

 

(2,861

)

25,501

 

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 Six
Months Ended June 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

 

$

(13,796

)

$

5,456

 

$

(8,340

)

Other current liabilities

 

(22,719

)

(3,864

)

(26,583

)

Change in other long-term assets

 

(5,542

)

(5,473

)

(11,015

)

Change in other long-term liabilities

 

(51,926

)

3,881

 

(48,045

)

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.  During the first quarter of 2011, APS refinanced an existing revolving credit facility (as discussed below) that would have otherwise matured in September 2011.

 

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.  On July 25, 2011, we repaid $25 million of the $175 million term loan facility.

 

At June 30, 2011, Pinnacle West’s $200 million credit facility, which matures in 2013, was available for bank borrowings, support of its $200 million commercial paper program, or for issuances of letters of credit.  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. At June 30, 2011, Pinnacle West had no outstanding borrowings under this credit facility, no outstanding letters of credit and commercial paper borrowings of $7 million.

 

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 will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

At June 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 June 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 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 June 30, 2011, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $3.7 billion, and total capitalization was approximately $7.1 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.8 billion, assuming APS’s total capitalization remains the same. 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 APS is now awaiting a procedural order from the ACC and expects a hearing will be scheduled for early 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.

 

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 an additional 100 MW of APS-owned AZ Sun projects and 25 MW of APS-owned facilities on schools.  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 spread 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.

 

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 liability for 2011 and 2010 (dollars in millions):

 

 

 

Six Months Ended
June 30,

 

 

 

2011

 

2010

 

Beginning balance

 

$

(58

)

$

(87

)

Deferred fuel and purchased power costs-current period

 

(65

)

(65

)

Amounts refunded through revenues

 

69

 

55

 

Ending balance

 

$

(54

)

$

(97

)

 

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.  The regulatory liability at June 30, 2011 reflects lower average prices, primarily for natural gas and gas-based generation.  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 transmission services used for APS’s retail customers.  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 June 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):

 

 

 

June 30, 2011

 

December 31, 2010

 

 

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Pension and other postretirement benefits

 

$

 

$

672

 

$

 

$

669

 

Deferred income taxes

 

3

 

72

 

3

 

69

 

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

 

31

 

32

 

42

 

35

 

Transmission vegetation management

 

9

 

36

 

 

46

 

Coal reclamation

 

2

 

36

 

2

 

36

 

Palo Verde VIE (Note 7)

 

 

34

 

 

33

 

Deferred compensation

 

 

34

 

 

32

 

Tax expense of Medicare subsidy

 

2

 

21

 

2

 

21

 

Loss on reacquired debt

 

1

 

20

 

1

 

21

 

Pension and other post-retirement benefits deferral

 

 

6

 

 

 

Demand side management (a)

 

8

 

5

 

12

 

6

 

Other

 

 

15

 

 

18

 

Total regulatory assets (b)

 

$

56

 

$

983

 

$

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.”

 

Included in the balance of regulatory assets at June 30, 2011 and December 31, 2010 is a regulatory asset for pension and other postretirement benefits.  This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income (“OCI”) and result in lower future earnings.

 

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

 

 

 

June 30, 2011

 

December 31, 2010

 

 

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Removal costs (a)

 

$

19

 

$

358

 

$

22

 

$

357

 

Asset retirement obligations (Note 15)

 

 

213

 

 

184

 

Deferred fuel and purchased power (b)(c)

 

54

 

 

58

 

 

Renewable energy standard (b)

 

57

 

 

50

 

 

Income taxes — change in rates

 

 

50

 

 

 

Spent nuclear fuel

 

4

 

43

 

4

 

41

 

Deferred gains on utility property

 

2

 

15

 

2

 

16

 

Other

 

7

 

16

 

3

 

16

 

Total regulatory liabilities

 

$

143

 

$

695

 

$

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.

 

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 a regulatory asset) (dollars in millions):

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

Three Months
Ended June 30,

 

Six Months
Ended June 30,

 

Three Months
Ended June 30,

 

Six Months
Ended June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Service cost - benefits earned during the period

 

$

13

 

$

13

 

$

29

 

$

28

 

$

5

 

$

5

 

$

11

 

$

10

 

Interest cost on benefit obligation

 

31

 

30

 

62

 

61

 

12

 

10

 

23

 

21

 

Expected return on plan assets

 

(33

)

(31

)

(67

)

(62

)

(11

)

(10

)

(21

)

(20

)

Amortization of:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transition obligation

 

 

 

 

 

 

(1

)

 

 

Prior service cost

 

 

 

1

 

1

 

 

 

 

 

Net actuarial loss

 

7

 

4

 

13

 

10

 

4

 

2

 

8

 

5

 

Net periodic benefit cost

 

$

18

 

$

16

 

$

38

 

$

38

 

$

10

 

$

6

 

$

21

 

$

16

 

Portion of cost charged to expense

 

$

7

 

$

8

 

$

15

 

$

19

 

$

4

 

$

3

 

$

8

 

$

8

 

 

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.  APS and other subsidiaries fund their respective shares of these contributions.  APS’s share is approximately 99% of both plans.

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 six months ended June 30, 2011 and 2010 and at June 30, 2011 and December 31, 2010 is provided as follows (dollars in millions):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Regulated electricity segment

 

$

799

 

$

800

 

$

1,447

 

$

1,411

 

All other

 

1

 

3

 

2

 

4

 

Total

 

$

800

 

$

803

 

$

1,449

 

$

1,415

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to common shareholders:

 

 

 

 

 

 

 

 

 

Regulated electricity segment

 

$

86

 

$

88

 

$

71

 

$

95

 

All other (a)

 

1

 

27

 

1

 

14

 

Total

 

$

87

 

$

115

 

$

72

 

$

109

 

 

 

 

As of
June 30, 2011

 

As of
December 31, 2010

 

Assets:

 

 

 

 

 

Regulated electricity segment

 

$

12,398

 

$

12,285

 

All other (a)

 

76

 

108

 

Total

 

$

12,474

 

$

12,393

 

 

 

(a)                                 All other activities relate to APSES, SunCor 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.  Consolidation of these VIEs eliminates the lease accounting and results in changes in our consolidated assets, debt, equity, and net income.  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 six months ended June 30, 2011 of $7 million and of $13 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 June 30, 2011 and December 31, 2010 include the following amounts relating to the VIEs (in millions):

 

 

 

June 30,
2011

 

December 31,
2010

 

Property plant and equipment, net of accumulated depreciation

 

$

135

 

$

138

 

Current maturities of long-term debt

 

30

 

29

 

Long-term debt less current maturities

 

83

 

97

 

Equity- Noncontrolling interests

 

101

 

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 June 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 June 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 these market fluctuations by utilizing various derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits.  Derivative instruments that are designated as cash flow hedges are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We may also invest in derivative instruments for trading purposes; however, for the period ended June 30, 2011, there was no material trading activity.

 

Our derivative instruments are accounted for at fair value; see Note 14 for a discussion of fair value measurements.  Derivative instruments for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales scope exception and are accounted for under the accrual method of accounting.  Due to the scope exception, these derivative instruments are excluded from our derivative instrument discussion and disclosures below.

 

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.  Economic hedges not designated as accounting hedges are recorded at fair value on our balance sheet with changes in fair value recognized in the statement of income as incurred.  These instruments are included in the “non-designated hedges” discussion and disclosure 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 June 30, 2011, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

 

In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy.  This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow.  We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but this does not impact our financial condition, net income or cash flows.

 

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 portion of APS’s base rates attributable to fuel and purchased power costs (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 June 30, 2011, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):

 

Commodity

 

Quantity

 

Power

 

13,226,728

megawatt hours

 

Gas

 

145,891,520

MMBTU (a)

 

 

(a)                                 “MMBTU” is one million British thermal units.

 

Derivative Instruments in Designated Accounting Hedging Relationships

 

The following table provides information about gains and losses from derivative instruments in designated accounting hedging relationships and their impact on our Condensed Consolidated Statements of Income during the three and six months ended June 30, 2011 and 2010 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

Commodity Contracts

 

Location

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount of Loss Recognized in AOCI on Derivative Instruments (Effective Portion)

 

Accumulated other comprehensive loss-derivative instruments

 

$

(16,324

)

$

(8,588

)

$

(15,335

)

$

(100,255

)

Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)

 

Regulated electricity segment fuel and purchased power

 

(25,287

)

(29,143

)

(40,133

)

(42,329

)

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

 

Regulated electricity segment fuel and purchased power

 

(176

)

11,899

 

(164

)

1,432

 

 

 

(a)                                 During the three and six months ended June 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 $89 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions.  Approximately 90% of the amounts related to derivatives subject to the PSA will be recorded as either a regulatory asset or liability and have no effect on earnings.

 

Derivative Instruments Not Designated as Accounting Hedges

 

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments and their impact on our Condensed Consolidated Statements of Income during the three and six months ended June 30, 2011 and 2010 (dollars in thousands):

 

 

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

Commodity Contracts

 

Financial Statement
Location

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount of Net Gain (Loss) Recognized in Income from Derivative Instruments

 

Regulated electricity segment revenue

 

$

(503

)

$

426

 

$

1,004

 

$

595

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount of Net Loss Recognized in Income from Derivative Instruments

 

Regulated electricity segment fuel and purchased power expense

 

(2,892

)

(29,260

)

(11,919

)

(64,228

)

Total

 

 

 

$

(3,395

)

$

(28,834

)

$

(10,915

)

$

(63,633

)

 

Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

 

The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis.  Transactions with counterparties that have master netting arrangements 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 June 30, 2011 (dollars in thousands):

 

Commodity Contracts

 

Current Assets

 

Investments
and Other Assets

 

Current
Liabilities

 

Deferred Credits
and Other

 

Total Assets
(Liabilities)

 

Derivatives designated as accounting hedging instruments:

 

 

 

 

 

 

 

 

 

 

 

Assets

 

$

329

 

$

 

$

11,730

 

$

3,011

 

$

15,070

 

Liabilities

 

(550

)

 

(90,187

)

(57,209

)

(147,946

)

Total hedging instruments

 

(221

)

 

(78,457

)

(54,198

)

(132,876

)

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as accounting hedging instruments:

 

 

 

 

 

 

 

 

 

 

 

Assets

 

24,607

 

43,173

 

31,946

 

10,365

 

110,091

 

Liabilities

 

(869

)

 

(94,294

)

(82,903

)

(178,066

)

Total non-hedging instruments

 

23,738

 

43,173

 

(62,348

)

(72,538

)

(67,975

)

 

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

23,517

 

43,173

 

(140,805

)

(126,736

)

(200,851

)

 

 

 

 

 

 

 

 

 

 

 

 

Margin account

 

2,137

 

 

11,087

 

3,862

 

17,086

 

Collateral provided to counterparties (a)

 

10,000

 

 

81,669

 

65,801

 

157,470

 

Collateral provided from counterparties (a)

 

 

 

(12,145

)

 

(12,145

)

Prepaid option premiums and other

 

3,243

 

 

1,510

 

 

4,753

 

Balance Sheet Total

 

$

38,897

 

$

43,173

 

$

(58,684

)

$

(57,073

)

$

(33,687

)

 

 

(a)                                 Amounts represent collateral relating to non-derivatives and derivative instruments, including those that qualify for scope exceptions.

 

The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis at December 31, 2010 (dollars in thousands):

 

Commodity Contracts

 

Current Assets

 

Investments
and Other Assets

 

Current
Liabilities

 

Deferred Credits
and Other

 

Total Assets
(Liabilities)

 

Derivatives designated as accounting hedging instruments:

 

 

 

 

 

 

 

 

 

 

 

Assets

 

$

1,234

 

$

142

 

$

9,062

 

$

4,913

 

$

15,351

 

Liabilities

 

(602

)

(1,933

)

(107,784

)

(71,109

)

(181,428

)

Total hedging instruments

 

632

 

(1,791

)

(98,722

)

(66,196

)

(166,077

)

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as accounting hedging instruments:

 

 

 

 

 

 

 

 

 

 

 

Assets

 

36,831

 

40,927

 

27,322

 

19,886

 

124,966

 

Liabilities

 

(312

)

(33

)

(112,535

)

(85,473

)

(198,353

)

Total non-hedging instruments

 

36,519

 

40,894

 

(85,213

)

(65,587

)

(73,387

)

 

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

37,151

 

39,103

 

(183,935

)

(131,783

)

(239,464

)

 

 

 

 

 

 

 

 

 

 

 

 

Margin account

 

24,579

 

 

997

 

 

25,576

 

Collateral provided to counterparties (a)

 

11,556

 

 

125,367

 

66,393

 

203,316

 

Collateral provided from counterparties (a)

 

(1,750

)

 

(1,250

)

 

(3,000

)

Prepaid option premiums and other

 

2,252

 

(71

)

(155

)

 

2,026

 

Balance Sheet Total

 

$

73,788

 

$

39,032

 

$

(58,976

)

$

(65,390

)

$

(11,546

)

 

 

(a)         Amounts represent collateral relating to non-derivatives and derivative instruments, including those that qualify for scope exceptions.

 

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 64% of Pinnacle West’s $82 million of risk management assets as of June 30, 2011.  This exposure relates to long-term traditional wholesale contracts with counterparties that have very 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.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on June 30, 2011 was $303 million, for which we had posted collateral of $147 million in the normal course of business.

 

For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit ratings were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).  If the investment grade contingent features underlying these agreements had been fully triggered on June 30, 2011, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $106 million of collateral to our counterparties; this amount includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the above footnote.  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 six months ended June 30, 2011 and 2010 (dollars in thousands):

 

 

 

Three Months Ended June 30, 2011

 

Three Months Ended June 30, 2010

 

 

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, April 1

 

$

3,631,411

 

$

97,360

 

$

3,728,771

 

$

3,213,933

 

$

116,067

 

$

3,330,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

86,685

 

7,154

 

93,839

 

114,797

 

4,769

 

119,566

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net unrealized losses on derivative instruments (a)

 

(16,324

)

 

(16,324

)

(8,588

)

 

(8,588

)

Net reclassification of realized losses to income (b)

 

25,287

 

 

25,287

 

29,143

 

 

29,143

 

Reclassification of pension and other postretirement benefits to income

 

1,046

 

 

1,046

 

1,362

 

 

1,362

 

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

 

974

 

 

974

 

(6,933

)

 

(6,933

)

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

 

(4,337

)

 

(4,337

)

(5,914

)

 

(5,914

)

Total other comprehensive income

 

6,646

 

 

6,646

 

9,070

 

 

9,070

 

Total comprehensive income

 

93,331

 

7,154

 

100,485

 

123,867

 

4,769

 

128,636

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

3,505

 

 

3,505

 

255,480

 

 

255,480

 

Other (primarily stock compensation)

 

(33

)

 

(33

)

140

 

 

140

 

Dividends on common stock

 

(114,509

)

 

(114,509

)

(113,872

)

 

(113,872

)

Net capital activities by noncontrolling interests

 

 

(2,609

)

(2,609

)

 

(7,381

)

(7,381

)

Ending balance, June 30

 

$

3,613,705

 

$

101,905

 

$

3,715,610

 

$

3,479,548

 

$

113,455

 

$

3,593,003

 

 

 

 

Six Months Ended June 30, 2011

 

Six Months Ended June 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

 

71,550

 

12,615

 

84,165

 

108,783

 

9,886

 

118,669

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net unrealized losses on derivative instruments (a)

 

(15,335

)

 

(15,335

)

(100,255

)

 

(100,255

)

Net reclassification of realized losses to income (b)

 

40,133

 

 

40,133

 

42,329

 

 

42,329

 

Reclassification of pension and other postretirement benefits to income

 

2,478

 

 

2,478

 

2,755

 

 

2,755

 

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

 

974

 

 

974

 

(6,933

)

 

(6,933

)