PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/3/2012
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2012
Apr. 27, 2012
Document and Entity Information
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Mar. 31, 2012 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
109,477,427 
Document Fiscal Year Focus
2012 
 
Document Fiscal Period Focus
Q1 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
OPERATING REVENUES
$ 620,631 
$ 648,847 
OPERATING EXPENSES
 
 
Fuel and purchased power
216,309 
212,007 
Operations and maintenance
210,663 
255,029 
Depreciation and amortization
100,109 
106,583 
Taxes other than income taxes
42,475 
37,624 
Other expenses
3,068 
1,820 
Total
572,624 
613,063 
OPERATING INCOME
48,007 
35,784 
OTHER INCOME (DEDUCTIONS)
 
 
Allowance for equity funds used during construction
4,756 
5,395 
Other income (Note 11)
760 
1,690 
Other expense (Note 11)
(4,068)
(1,741)
Total
1,448 
5,344 
INTEREST EXPENSE
 
 
Interest charges
56,967 
61,077 
Allowance for borrowed funds used during construction
(3,151)
(3,576)
Total
53,816 
57,501 
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(4,361)
(16,373)
INCOME TAXES
(4,645)
(6,005)
INCOME (LOSS) FROM CONTINUING OPERATIONS
284 
(10,368)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
 
 
Net of income tax expense (benefit) of $(505) and $330 (Note 13)
(765)
694 
NET INCOME (LOSS)
(481)
(9,674)
Less: Net income attributable to noncontrolling interests (Note 7)
7,776 
5,461 
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS
(8,257)
(15,135)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
109,299 
108,832 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
109,299 
108,832 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
Loss from continuing operations attributable to common shareholders - basic (in dollars per share)
$ (0.07)
$ (0.15)
Net loss attributable to common shareholders - basic (in dollars per share)
$ (0.08)
$ (0.14)
Loss from continuing operations attributable to common shareholders - diluted (in dollars per share)
$ (0.07)
$ (0.15)
Net loss attributable to common shareholders - diluted (in dollars per share)
$ (0.08)
$ (0.14)
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 0.525 
$ 0.525 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
Loss from continuing operations, net of tax
(7,483)
(15,838)
Discontinued operations, net of tax
(774)
703 
Net loss attributable to common shareholders
$ (8,257)
$ (15,135)
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Income tax expense (benefit) on discontinued operations
$ (505)
$ 330 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
NET INCOME (LOSS)
$ (481)
$ (9,674)
Derivative instruments:
 
 
Net unrealized gain (loss), net of tax benefit (expense) of $16,551 and $(390)
(25,352)
598 
Reclassification of net realized loss, net of tax benefit of $5,728 and $5,865
8,772 
8,982 
Pension and other postretirement benefits activity, net of tax expense of $631 and $566
966 
866 
Total other comprehensive income (loss)
(15,614)
10,446 
COMPREHENSIVE INCOME (LOSS)
(16,095)
772 
Less: Comprehensive income attributable to noncontrolling interests
7,776 
5,461 
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ (23,871)
$ (4,689)
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Net unrealized gains (loss), tax benefit (expense)
$ 16,551 
$ (390)
Reclassification of net realized loss, tax benefit
5,728 
5,865 
Pension and other postretirement benefits activity, tax expense
$ 631 
$ 566 
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 20,710 
$ 33,583 
Customer and other receivables
238,387 
284,183 
Accrued unbilled revenues
104,728 
125,239 
Allowance for doubtful accounts
(2,886)
(3,748)
Materials and supplies (at average cost)
213,290 
204,387 
Fossil fuel (at average cost)
26,850 
22,000 
Deferred income taxes
141,224 
130,571 
Income tax receivable (Note 6)
8,894 
6,466 
Assets from risk management activities (Note 8)
34,617 
30,264 
Deferred fuel and purchased power regulatory asset (Note 3)
5,310 
27,549 
Other regulatory assets (Note 3)
81,457 
69,072 
Other current assets
32,219 
26,904 
Total current assets
904,800 
956,470 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 8)
53,124 
49,322 
Nuclear decommissioning trust (Note 15)
541,989 
513,733 
Other assets
64,415 
64,588 
Total investments and other assets
659,528 
627,643 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
13,928,709 
13,753,971 
Accumulated depreciation and amortization
(4,775,904)
(4,709,991)
Net
9,152,805 
9,043,980 
Construction work in progress
462,425 
496,745 
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)
131,897 
132,864 
Intangible assets, net of accumulated amortization
170,198 
170,571 
Nuclear fuel, net of accumulated amortization
141,882 
118,098 
Total property, plant and equipment
10,059,207 
9,962,258 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,344,523 
1,352,079 
Income tax receivable (Note 6)
69,069 
68,633 
Other
146,787 
143,935 
Total deferred debits
1,560,379 
1,564,647 
TOTAL ASSETS
13,183,914 
13,111,018 
CURRENT LIABILITIES
 
 
Accounts payable
265,975 
326,987 
Accrued taxes (Note 6)
160,136 
120,289 
Accrued interest
44,736 
54,872 
Short-term borrowings
216,600 
 
Current maturities of long-term debt
101,708 
477,435 
Customer deposits
74,297 
72,176 
Liabilities from risk management activities (Note 8)
89,207 
53,968 
Regulatory liabilities (Note 3)
89,622 
88,362 
Other current liabilities
115,618 
148,616 
Total current liabilities
1,157,899 
1,342,705 
LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
Long-term debt less current maturities
3,275,651 
2,953,507 
Palo Verde sale leaseback lessor notes less current maturities (Note 7)
65,547 
65,547 
Total long-term debt less current maturities
3,341,198 
3,019,054 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
1,918,995 
1,925,388 
Regulatory liabilities (Note 3)
754,210 
737,332 
Liability for asset retirements
284,839 
279,643 
Liabilities for pension and other postretirement benefits (Note 4)
1,277,227 
1,268,910 
Liabilities from risk management activities (Note 8)
64,168 
82,495 
Customer advances
113,514 
116,805 
Coal mine reclamation
118,113 
117,896 
Unrecognized tax benefits (Note 6)
72,622 
72,270 
Other
219,700 
217,934 
Total deferred credits and other
4,823,388 
4,818,673 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY (Note 9)
 
 
Common stock, no par value
2,450,296 
2,444,247 
Treasury stock
(6,471)
(4,717)
Total common stock
2,443,825 
2,439,530 
Retained earnings
1,468,869 
1,534,483 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(64,481)
(65,447)
Derivative instruments
(103,296)
(86,716)
Total accumulated other comprehensive loss
(167,777)
(152,163)
Total shareholders' equity
3,744,917 
3,821,850 
Noncontrolling interests (Note 7)
116,512 
108,736 
Total equity
3,861,429 
3,930,586 
TOTAL LIABILITIES AND EQUITY
$ 13,183,914 
$ 13,111,018 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME (LOSS)
$ (481)
$ (9,674)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
118,487 
123,298 
Deferred fuel and purchased power
46,754 
49,947 
Deferred fuel and purchased power amortization
(24,514)
(31,238)
Allowance for equity funds used during construction
(4,756)
(5,395)
Deferred income taxes
(1,989)
(41,005)
Change in mark-to-market valuations
1,985 
(284)
Changes in current assets and liabilities:
 
 
Customer and other receivables
52,264 
75,528 
Accrued unbilled revenues
20,511 
9,633 
Materials, supplies and fossil fuel
(13,753)
21,421 
Other current assets
(3,502)
(636)
Accounts payable
(39,355)
(24,543)
Accrued taxes and income tax receivable - net
37,398 
52,944 
Other current liabilities
(39,804)
(37,406)
Change in unrecognized tax benefits
 
18,959 
Change in margin and collateral accounts - assets
(1,853)
4,220 
Change in margin and collateral accounts - liabilities
(32,950)
35,478 
Change in other long-term assets
(21,469)
(33,169)
Change in other long-term liabilities
22,362 
35,418 
Net cash flow provided by operating activities
115,335 
243,496 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(240,973)
(191,553)
Contributions in aid of construction
13,871 
9,136 
Allowance for borrowed funds used during construction
(3,151)
(3,576)
Proceeds from nuclear decommissioning trust sales
92,047 
189,318 
Investment in nuclear decommissioning trust
(96,360)
(194,241)
Other
(533)
(1,879)
Net cash flow used for investing activities
(235,099)
(192,795)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
319,081 
175,000 
Repayment of long-term debt
(375,727)
(175,170)
Short-term borrowings and payments - net
216,600 
700 
Dividends paid on common stock
(55,595)
(55,300)
Common stock equity issuance
4,289 
11,727 
Other
(1,757)
(3,653)
Net cash flow provided by (used for) financing activities
106,891 
(46,696)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(12,873)
4,005 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
33,583 
110,188 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
20,710 
114,193 
Cash paid during the period for:
 
 
Income taxes, net of (refunds)
(650)
 
Interest, net of amounts capitalized
$ 62,892 
$ 55,997 
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”), El Dorado Investment Company (“El Dorado”) and formerly APS Energy Services Company, Inc. (“APSES”).  See Note 13 for discussion of the bankruptcy filing of SunCor and the sale 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.

 

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 2011 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income in accordance with accounting requirements for reporting discontinued operations (see Note 13) and to conform to current year presentation, and on our Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.

 

See Note 16 for discussion of amended guidance on the presentation of comprehensive income.

 

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 March 31, 2011

 

As
previously
reported

 

Reclassifications
for discontinued
operations and to
conform to
current year
presentation

 

Amount
reported after
reclassification
for discontinued
operations and
to conform to
current year
presentation

 

Operating Revenues

 

 

 

 

 

 

 

Regulated electricity segment revenues

 

$

647,974

 

$

(647,974

)

$

 

Other revenues

 

11,601

 

(11,601

)

 

Operating revenues

 

 

648,847

 

648,847

 

Operating Expenses

 

 

 

 

 

 

 

Operations and maintenance

 

256,486

 

(1,457

)

255,029

 

Depreciation and amortization

 

106,601

 

(18

)

106,583

 

Other expenses

 

9,716

 

(7,896

)

1,820

 

Other

 

 

 

 

 

 

 

Other expense

 

(1,699

)

(42

)

(1,741

)

Income Taxes

 

(5,649

)

(356

)

(6,005

)

Income From Continuing Operations

 

(9,325

)

(1,043

)

(10,368

)

Income From Discontinued Operations

 

(349

)

1,043

 

694

 

 

Statement of Cash Flows for the
Three Months Ended March 31,
2011

 

As
previously
reported

 

Reclassifications
to conform to
current year
presentation

 

Amount
reported after
reclassification
to conform to
current year
presentation

 

Cash Flows from Operating Activities

 

 

 

 

 

 

 

Expenditures for real estate investments

 

$

(40

)

$

40

 

$

 

Gains and other changes in real estate assets

 

(3

)

3

 

 

Change in other long-term assets

 

(33,129

)

(40

)

(33,169

)

Change in other long-term liabilities

 

35,421

 

(3

)

35,418

 

 

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

 

At March 31, 2012, Pinnacle West’s $200 million credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  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 March 31, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

 

APS

 

On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012.

 

At March 31, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, and a $500 million facility that matures in November 2016.  APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2012, APS had commercial paper borrowings of $217 million, and no borrowings or letters of credit outstanding under either of these credit facilities.

 

On May 1, 2012, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011.

 

See “Financial Assurances” in Note 10 for discussion of APS’s outstanding 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, and are classified within Level 2 of the fair value hierarchy. See Note 14 for discussion of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 

 

 

As of
March 31, 2012

 

As of
December 31, 2011

 

 

 

Carrying
Amount

 

Fair Value

 

Carrying
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Pinnacle West

 

$

125

 

$

123

 

$

125

 

$

123

 

APS

 

3,318

 

3,748

 

3,371

 

3,803

 

Total

 

$

3,443

 

$

3,871

 

$

3,496

 

$

3,926

 

 

Debt Provisions

 

An 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 March 31, 2012, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $3.9 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.  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 cash needs.

 

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.  APS 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.  On January 6, 2012, APS and other parties to APS’s pending general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have agreed to settle the rate case.  The Settlement Agreement requires the approval of the ACC.  Evidentiary hearings on the matter were completed on February 3, 2012 and briefs from the parties were filed on February 29, 2012.  See below for details regarding the Settlement Agreement.

 

The key financial provisions of APS’s original 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 APS’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 (“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).

 

APS 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 a decoupling mechanism, which would address recovery of APS’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.

 

Settlement Agreement

 

The Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff (“RES”) surcharge to base rates in an estimated amount of $36.8 million.

 

APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016.  The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest.  Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement.

 

Other key provisions of the Settlement Agreement include the following:

 

·                                          An authorized return on common equity of 10.0%;

 

·                                          A capital structure comprised of 46.1% debt and 53.9% common equity;

 

·                                          A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;

 

·                                          Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:

 

·                                          Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

 

·                                          Deferral of 100% in all years if Arizona property tax rates decrease;

 

·                                          A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant (“Four Corners”);

 

·                                          Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;

 

·                                          Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce approximately $5 million annually;

 

·                                          Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

 

·                                          Allowing a negative credit that currently exists in the PSA to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

 

·                                          Modification of the transmission cost adjustor (“TCA”) to streamline the process for future transmission-related rate changes; and

 

·                                          Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.

 

If the Settlement Agreement is approved by the ACC, APS expects that its provisions will become effective on or about July 1, 2012.  As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.

 

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 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.

 

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.  On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million.  Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 megawatts (“MW”) under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015.  In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications.  Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.

 

Demand-Side Management Adjustor Charge (“DSMAC”).  The settlement agreement resulting from the 2008 retail rate case requires APS to submit an annual Demand-Side Management Implementation Plan for review by and approval of the ACC.  In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand-side management programs over the current year.  Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis.  The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives.

 

The ACC previously 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 2008 retail rate case 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 Demand-Side Management 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 in the previous paragraph less the $10 million already being recovered in general retail base 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 Demand-Side Management 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 2008 retail rate case settlement agreement (1.5% of total energy resources). The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates.

 

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 2012 and 2011 (dollars in millions):

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Beginning balance

 

$

28

 

$

(58

)

Deferred fuel and purchased power costs — current period

 

(47

)

(50

)

Amounts refunded through revenues

 

24

 

31

 

Ending balance

 

$

5

 

$

(77

)

 

The PSA rate for the PSA year beginning February 1, 2012 is negative $0.0042 per kWh as compared to negative $0.0057 per kWh for the prior year.  Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.

 

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 TCA.  If the Settlement Agreement (discussed above) is approved, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

 

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

 

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

 

 

 

March 31, 2012

 

December 31, 2011

 

 

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Pension and other postretirement benefits

 

$

 

$

1,007

 

$

 

$

1,023

 

Income taxes — allowance for funds used during construction (“AFUDC”) equity

 

3

 

81

 

3

 

81

 

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

 

58

 

34

 

43

 

34

 

Transmission vegetation management

 

9

 

30

 

9

 

32

 

Coal reclamation

 

2

 

34

 

2

 

35

 

Palo Verde VIEs (Note 7)

 

 

36

 

 

35

 

Deferred compensation

 

 

34

 

 

33

 

Deferred fuel and purchased power (a)

 

5

 

 

28

 

 

Tax expense of Medicare subsidy

 

2

 

19

 

2

 

18

 

Loss on reacquired debt

 

1

 

19

 

1

 

19

 

Income taxes — investment tax credit basis adjustment

 

 

15

 

 

15

 

Pension and other postretirement benefits deferral

 

 

21

 

 

12

 

Demand-side management (a)

 

5

 

 

7

 

1

 

Other

 

2

 

15

 

2

 

14

 

Total regulatory assets (b)

 

$

87

 

$

1,345

 

$

97

 

$

1,352

 

 

(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):

 

 

 

March 31, 2012

 

December 31, 2011

 

 

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Removal costs (a)

 

$

24

 

$

344

 

$

22

 

$

349

 

Asset retirement obligations

 

 

249

 

 

225

 

Renewable energy standard (b)

 

50

 

 

54

 

 

Income taxes — change in rates

 

 

59

 

 

59

 

Spent nuclear fuel

 

7

 

41

 

5

 

44

 

Deferred gains on utility property

 

2

 

14

 

2

 

14

 

Income taxes- deferred investment tax credit

 

1

 

32

 

1

 

30

 

Other

 

6

 

15

 

4

 

16

 

Total regulatory liabilities

 

$

90

 

$

754

 

$

88

 

$

737

 

 

(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.

 

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.  We deferred pension and other postretirement benefit costs of approximately $9 million for the three months ended March 31, 2012 and $3 million for the three months ended March 31, 2011.  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
March 31,

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

2012

 

2011

 

Service cost - benefits earned during the period

 

$

16

 

$

16

 

$

7

 

$

6

 

Interest cost on benefit obligation

 

30

 

31

 

12

 

12

 

Expected return on plan assets

 

(35

)

(33

)

(11

)

(10

)

Amortization of net actuarial loss

 

11

 

6

 

6

 

3

 

Net periodic benefit cost

 

$

22

 

$

20

 

$

14

 

$

11

 

Portion of cost charged to expense

 

$

6

 

$

8

 

$

3

 

$

4

 

 

Contributions

 

The required minimum contribution to our pension plan is approximately $65 million in 2012, approximately $160 million in 2013 and approximately $175 million in 2014.  The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 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 months ended March 31, 2012 and 2011 and at March 31, 2012 and December 31, 2011 is provided as follows (dollars in millions):

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Operating revenues:

 

 

 

 

 

Regulated electricity segment

 

$

620

 

$

648

 

All other (a)

 

1

 

1

 

Total

 

$

621

 

$

649

 

 

 

 

 

 

 

Net loss attributable to common shareholders:

 

 

 

 

 

Regulated electricity segment

 

$

(6

)

$

(15

)

All other (a)

 

(2

)

 

Total

 

$

(8

)

$

(15

)

 

 

 

As of
March 31, 2012

 

As of
December 31, 2011

 

Assets:

 

 

 

 

 

Regulated electricity segment

 

$

13,142

 

$

13,068

 

All other (a)

 

42

 

43

 

Total

 

$

13,184

 

$

13,111

 

 

(a)                                  All other activities relate to APSES, SunCor, Pinnacle West and El Dorado.  See Note 13 for discussion of discontinued operations.

 

Income Taxes
Income Taxes

6.                                      Income Taxes

 

The $69 million income tax receivable on the Condensed Consolidated Balance Sheets primarily 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 there remains uncertainty regarding the timing of this cash receipt. Further clarification of the timing is expected from the IRS within the next twelve months.

 

Net income associated with the Palo Verde Sale Leaseback Variable Interest Entities is not subject to tax (see Note 7).  As a result, there is no income tax expense recorded on the Condensed Consolidated Statements of Income.

 

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009. At this time, a reasonable estimate of the range of possible change in the uncertain tax position cannot be made.  However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

 

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.

 

As of March 31, 2012, 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 2007.

 

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.  APS will pay approximately $49 million per year for the years 2012 to 2015 related to these leases. The lease agreements include fixed rate renewal periods which may give APS the ability to utilize the asset for a significant portion of the asset’s economic life.  Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

 

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 months ended March 31, 2012 of $8 million and for the three months ended March 31, 2011 of $5 million, 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 March 31, 2012 and December 31, 2011 include the following amounts relating to the VIEs (in millions):

 

 

 

March 31,
2012

 

December 31,
2011

 

Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation

 

$

132

 

$

133

 

Current maturities of long-term debt

 

31

 

31

 

Palo Verde sale leaseback lessor notes long-term debt excluding current maturities

 

66

 

66

 

Equity — Noncontrolling interests

 

116

 

108

 

 

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.

 

APS is exposed to losses relating to these 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 March 31, 2012, APS would have been required to pay the noncontrolling equity participants approximately $141 million and assume $97 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

 

For regulatory ratemaking purposes the leases continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

 

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, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed 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 other comprehensive income (“OCI”) 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 March 31, 2012, 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 March 31, 2012, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

 

Commodity

 

Quantity

 

Power

 

11,048

 

gigawatt hours

 

Gas

 

146

 

Bcfs (a)

 

 

(a)                                  “Bcf” is Billion Cubic Feet.

 

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 months ended March 31, 2012 and 2011 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
March 31,

 

Commodity Contracts

 

Location

 

2012

 

2011

 

 

 

 

 

 

 

 

 

Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)

 

Other comprehensive income (loss) — derivative instruments

 

$

(41,903

)

$

988

 

Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized)

 

Fuel and purchased power

 

(14,500

)

(14,847

)

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

 

Fuel and purchased power

 

85

 

12

 

 

(a)                                  During the three months ended March 31, 2012 and 2011, we had no amounts reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges.

 

During the next twelve months, we estimate that a net loss of $97 million before income taxes will be reclassified from accumulated other comprehensive income 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 months ended March 31, 2012 and 2011 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
March 31,

 

Commodity Contracts

 

Location

 

2012

 

2011

 

 

 

 

 

 

 

 

 

Net Gain (Loss) Recognized in Income

 

Operating revenues

 

$

(326

)

$

1,507

 

 

 

 

 

 

 

 

 

Net Loss Recognized in Income from Derivative Instruments

 

Fuel and purchased power expense

 

(25,052

)

(9,026

)

Total

 

 

 

$

(25,378

)

$

(7,519

)

 

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 March 31, 2012 (dollars in thousands):

 

Commodity Contracts

 

Designated
as Hedging
Instruments

 

Not
Designated
as Hedging
Instruments

 

Margin and
Collateral
Provided to
Counterparties

 

Collateral
Provided from
Counterparties
(a)

 

Other (b)

 

Total

 

Current Assets

 

$

6,466

 

$

80,364

 

$

3,486

 

$

 

$

(55,699

)

$

34,617

 

Investments and Other Assets

 

3,377

 

57,639

 

 

 

(7,892

)

53,124

 

Total Assets

 

9,843

 

138,003

 

$

3,486

 

$

 

(63,591

)

87,741

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(103,592

)

(131,751

)

100,228

 

(11,145

)

57,053

 

(89,207

)

Deferred Credits and Other

 

(80,252

)

(97,503

)

105,718

 

 

7,869

 

(64,168

)

Total Liabilities

 

(183,844

)

(229,254

)

205,946

 

(11,145

)

64,922

 

(153,375

)

Total

 

$

(174,001

)

$

(91,251

)

$

209,432

 

$

(11,145

)

$

1,331

 

$

(65,634

)

 

(a)                                  Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

 

(b)                                 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, 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
(a)

 

Other (b)

 

Total

 

Current Assets

 

$

7,287

 

$

76,162

 

$

1,630

 

$

 

$

(54,815

)

$

30,264

 

Investments and Other Assets

 

3,804

 

58,273

 

 

 

(12,755

)

49,322

 

Total Assets

 

11,091

 

134,435

 

1,630

 

 

(67,570

)

79,586

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(82,195

)

(124,028

)

107,228

 

(11,145

)

56,172

 

(53,968

)

Deferred Credits and Other

 

(68,137

)

(92,880

)

65,768

 

 

12,754

 

(82,495

)

Total Liabilities

 

(150,332

)

(216,908

)

172,996

 

(11,145

)

68,926

 

(136,463

)

Total Derivative Instruments

 

$

(139,241

)

$

(82,473

)

$

174,626

 

$

(11,145

)

$

1,356

 

$

(56,877

)

 

(a)                                  Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

 

(b)                                 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 83% of Pinnacle West’s $88 million of risk management assets as of March 31, 2012.  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 March 31, 2012 (dollars in millions):

 

 

 

March 31,
2012

 

Aggregate Fair Value of Derivative Instruments in a Net Liability Position

 

$

380

 

Cash Collateral Posted

 

180

 

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

 

169

 

 

(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 $184 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 months ended March 31, 2012 and 2011 (dollars in thousands):

 

 

 

Three Months Ended March 31, 2012

 

Three Months Ended March 31, 2011

 

 

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, January 1

 

$

3,821,850

 

$

108,736

 

$

3,930,586

 

$

3,683,327

 

$

91,899

 

$

3,775,226

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

(8,257

)

7,776

 

(481

)

(15,135

)

5,461

 

(9,674

)

OCI (loss)

 

(15,614

)

 

(15,614

)

10,446

 

 

10,446

 

Total comprehensive income (loss)

 

(23,871

)

7,776

 

(16,095

)

(4,689

)

5,461

 

772

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

2,700

 

 

2,700

 

2,689

 

 

2,689

 

Purchase of treasury stock, net of reissuances

 

(1,754

)

 

(1,754

)

(3,530

)

 

(3,530

)

Other (primarily stock compensation)

 

3,350

 

 

3,350

 

10,723

 

 

10,723

 

Dividends on common stock

 

(57,358

)

 

(57,358

)

(57,109

)

 

(57,109

)

Ending balance, March 31

 

$

3,744,917

 

$

116,512

 

$

3,861,429

 

$

3,631,411

 

$

97,360

 

$

3,728,771

 

 

Commitments and Contingencies
Commitments and Contingencies

10.                               Commitments and Contingencies

 

Palo Verde Nuclear Generating Station

 

Spent Nuclear Fuel and Waste Disposal

 

APS currently estimates it will incur $122 million (in 2012 dollars) over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel.  At March 31, 2012, APS had a regulatory liability of $48 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

 

Nuclear Insurance

 

The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence.  As required by the Price Anderson Nuclear Industries Indemnity Act, Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers.  The remaining balance of $12.2 billion is provided through a mandatory industry wide retrospective assessment program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments.  The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation.  Based on APS’s interest in the three Palo Verde units, APS’s maximum potential assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million.

 

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination.  APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”).  APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds.  The maximum amount APS could incur under the current NEIL policies totals approximately $18 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $48 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

 

Contractual Obligations

 

As of March 31, 2012, certain contractual obligations have increased approximately $0.3 billion from December 31, 2011 as discussed in the 2011 Form 10-K.  The updated contractual obligations are as follows (dollars in billions):

 

Year

 

2012

 

2013

 

2014

 

2015

 

2016

 

Thereafter

 

Total

 

Fuel and purchased power commitments

 

$

0.4

 

$

0.4

 

$

0.6

 

$

0.5

 

$

0.5

 

$

6.8

 

$

9.2

 

Renewable energy credits

 

0.1

 

 

 

0.1

 

 

0.5

 

0.7

 

 

FERC Market Issues

 

On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest.  The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding.  This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit and ultimately remanded to the FERC for further consideration.  On October 3, 2011, the FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001.  FERC rejected a market-wide remedy approach and instead directed that buyers seeking refunds must demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.

 

This hearing has been held in abeyance to provide an opportunity for the parties to engage in settlement negotiations.  Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

 

Superfund

 

The Comprehensive Environmental Response, Compensation and Liability Act (“Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties (“PRPs”).  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, the United States Environmental Protection Agency (“EPA”) advised APS that the EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with the EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan.  We estimate that our costs related to this investigation and study will be approximately $1 million.  We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time we cannot accurately estimate our total expenditures.

 

Climate Change Lawsuit

 

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law.  The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages.  In June 2008, the defendants filed motions to dismiss the action, which were granted.  The plaintiffs filed an appeal with the Ninth Circuit Court of Appeals in November 2009, and Pinnacle West filed its reply on June 30, 2010.  On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.

 

On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants.  However, the Court left open the issue of whether such claims may be available under state law.  Oral argument in the Kivalina case was heard on November 28, 2011; the parties await the court’s decision on both federal common law and state public nuisance law issues.  We believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.

 

Southwest Power Outage

 

Regulatory Inquiry.  On September 8, 2011 at approximately 3:30PM, a 500 kilovolt (“kV”) transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS.  At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly.  Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.

 

Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico.  A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected.  Service to all affected APS customers was restored by 9:15PM on September 8.  Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9.

 

APS has an internal review of the September 8 events underway.  In addition, the Western Electricity Coordinating Council (“WECC”) initiated a Detailed Disturbance Analysis process to identify and understand the cause of the events that occurred, and identify and ensure timely implementation of corrective actions.

 

The FERC and the North American Electric Reliability Corporation (“NERC”) conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report with their analysis and conclusions as to the causes of the events. The report includes recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination.

 

The joint report does not address potential reliability violations or the assessment of responsibility of the parties involved. APS cannot predict the timing, results or potential impacts of any further inquiries into the September 8 events, or any other claims that may be made as a result of the outages. If violations of NERC Reliability Standards are ultimately determined to have occurred, FERC has the legal authority to assert a possible fine of up to $1 million per violation per day that a violation is found to have been in existence.

 

Lawsuit.  On September 12, 2011, two purported consumer class action complaints were filed in Federal District Court in San Diego, California, naming APS, Pinnacle West and San Diego Gas & Electric Company (“SDG&E”) as defendants and seeking damages for loss of perishable inventory as a result of interruption of electrical service.  On December 22, 2011, the plaintiffs voluntarily dismissed both lawsuits.  In January 2012, one of the cases was refiled in California Superior Court in San Diego, California.  APS and Pinnacle West filed a motion to dismiss that was granted by the Court on March 20, 2012.  The case was stayed as to SDG&E until the earlier of six months or the release of a FERC or California Public Utilities Commission (“CPUC”) report on the outage.  The Court stated that the plaintiffs may refile a complaint against APS and Pinnacle West on certain grounds following the release of either report.

 

Clean Air Act Lawsuit

 

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act.  Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s New Source Performance Standards (“NSPS”) program.  Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the NSPS.  The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project.  On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss with the court.  Earthjustice’s responses to these motions are due May 16, 2012.  APS believes the claims in this matter are without merit and will vigorously defend against them.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

 

Financial Assurances

 

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At March 31, 2012, approximately $44 million of letters of credit were outstanding to support existing variable interest rate pollution control bonds of a similar amount.  The letters of credit are available to fund the payment of principal and interest of such debt obligations.  These letters of credit expire in 2016.  APS has also entered into letters of credit to support obligations to certain equity participants in the Palo Verde sale leaseback transactions (see Note 7 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire in 2015 and totaled approximately $44 million at March 31, 2012.  Additionally, APS has issued letters of credit to support collateral obligations under certain natural gas tolling contracts entered into with third parties.  At March 31, 2012, $30 million of such letters of credit were outstanding.  These letters of credit will expire in 2015 and 2016.

 

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

 

Other Income and Other Expense
Other Income and Other Expense

11.          Other Income and Other Expense

 

The following table provides detail of other income and other expense for the three months ended March 31, 2012 and 2011 (dollars in thousands):

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

Other income:

 

 

 

 

 

Interest income

 

$

605

 

$

391

 

Investment gains — net

 

 

1,293

 

Miscellaneous

 

155

 

6

 

Total other income

 

$

760

 

$

1,690

 

 

 

 

 

 

 

Other expense:

 

 

 

 

 

Non-operating costs

 

$

(1,850

)

$

(1,487

)

Investment losses — net

 

(53

)

 

Miscellaneous

 

(2,165

)

(254

)

Total other expense

 

$

(4,068

)

$

(1,741

)

 

Earnings Per Share
Earnings Per Share

12.          Earnings Per Share

 

The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2012 and 2011:

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Basic earnings per share:

 

 

 

 

 

Loss from continuing operations attributable to common shareholders

 

$

(0.07

)

$

(0.15

)

Income (loss) from discontinued operations

 

(0.01

)

0.01

 

Loss per share — basic

 

$

(0.08

)

$

(0.14

)

 

 

 

 

 

 

Diluted earnings per share:

 

 

 

 

 

Loss from continuing operations attributable to common shareholders

 

$

(0.07

)

$

(0.15

)

Income (loss) from discontinued operations

 

(0.01

)

0.01

 

Loss per share — diluted

 

$

(0.08

)

$

(0.14

)

 

For the three months ended March 31, 2012 and 2011, the weighted average common shares outstanding were the same for both basic and diluted shares.

 

For the three months ended March 31, 2012 and 2011, options to purchase shares of common stock were outstanding but excluded from the computation of diluted earnings per share because of their antidilutive effect.  This is a result of the net loss position in both periods.

 

Discontinued Operations
Discontinued Operations

13.          Discontinued Operations

 

SunCor — In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations, or cash flows.  All activity for the income statement for the three months ended March 31, 2012 and prior comparative period income statement amounts are included in discontinued operations.  At March 31, 2012, SunCor had approximately $8 million of assets on its balance sheet, including $7 million of intercompany receivables and $1 million of other assets.

 

APSES In 2011, Pinnacle West sold its investment in APSES.  Prior-period income statement amounts related to the sale of APSES and the associated revenues and costs are reflected in discontinued operations.

 

The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011 (dollars in millions):

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Revenue:

 

 

 

 

 

SunCor

 

$

 

$

1

 

APSES

 

 

11

 

Total revenue

 

$

 

$

12

 

 

 

 

 

 

 

Income (loss) before taxes:

 

$

(1

)

$

1

 

Income (loss) after taxes:

 

$

(1

)

$

1

 

 

Fair Value Measurements
Fair Value Measurements

14.          Fair Value Measurements

 

We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:

 

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.  This category includes exchange-traded equities, exchange-traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities.

 

Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves).  This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities.  This category also includes investments in common and collective trusts and commingled funds that are redeemable and valued based on the funds’ net asset values (“NAV”).

 

Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

 

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

 

Recurring Fair Value Measurements

 

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans.  See Note 8 in the 2011 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.

 

Cash Equivalents

 

Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.

 

Risk Management Activities — Derivative Instruments

 

Exchange traded commodity contracts are valued using unadjusted quoted prices.  For non-exchange traded commodity contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value.  We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.  These include valuation adjustments for liquidity and credit risks.  The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged.  The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio.  We maintain credit policies that management believes minimize overall credit risk.

 

Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions.  Our long-dated energy transactions consist of observable valuations for the near term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When broker quotes are not available the primary valuation technique used to calculate fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points. 

 

Option contracts are primarily valued using a Black-Scholes option valuation model which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities.

 

When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.  Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs.

 

Investments Held in our Nuclear Decommissioning Trust

 

The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds.  The commingled funds are valued based on NAV, which is primarily derived from the quoted active market prices of the underlying equity securities.  We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2.  The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 index.  Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

 

Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities.  We may transact in this commingled fund on a daily basis at the NAV.

 

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies including mortgage-backed instruments are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield and interest rate curves.  These instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.

 

Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services that utilize the valuation methodologies described to determine fair market value.  We assess these valuations and verify that pricing can be supported by actual recent market transactions.  Additionally, we obtain and review independent audit reports on the trustee’s operating controls and valuation processes.  See Note 15 for additional discussion about our nuclear decommissioning trust.

 

Fair Value Tables

 

The following table presents the fair value at March 31, 2012 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

 

 

 

Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs (a)
(Level 3)

 

Other

 

Balance at
March 31,
2012

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trust:

 

 

 

 

 

 

 

 

 

 

 

U.S. commingled equity funds

 

$

 

$

196

 

$

 

$

 

$

196

 

Fixed income securities:

 

 

 

 

 

 

 

 

 

 

 

U.S. Treasury

 

76

 

 

 

 

76

 

Cash and cash equivalent funds

 

 

15

 

 

(1

)(c)

14

 

Corporate debt

 

 

67

 

 

 

67

 

Mortgage-backed securities

 

 

82

 

 

 

82

 

Municipality bonds

 

 

88

 

 

 

88

 

Other

 

 

19

 

 

 

19

 

Subtotal nuclear decommissioning trust

 

76

 

467

 

 

(1

)

542

 

Cash Equivalents

 

12

 

 

 

 

12

 

Risk management activities — derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

 

63

 

84

 

(59

)(b)

88

 

Total

 

$

88

 

$

530

 

$

84

 

$

(60

)

$

642

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

Risk management activities — derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

 

$

(271

)

$

(142

)

$

260

(b)

$

(153

)

 

(a)                                  Primarily consists of heat rate options and long-dated electricity contracts.

(b)                                 Represents counterparty netting, margin and collateral (see Note 8).

(c)                                  Represents nuclear decommissioning trust net pending securities sales and purchases.

 

The following table presents the fair value at December 31, 2011 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

 

 

 

Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs (a)
(Level 3)

 

Other

 

Balance at
December 31,
2011

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trust:

 

 

 

 

 

 

 

 

 

 

 

U.S. commingled equity funds

 

$

 

$

175

 

$

 

$

 

$

175

 

Fixed income securities:

 

 

 

 

 

 

 

 

 

 

 

U.S. Treasury

 

69

 

 

 

 

69

 

Cash and cash equivalent funds

 

 

9

 

 

(1

)(c)

8

 

Corporate debt

 

 

73