PINNACLE WEST CAPITAL CORP, 10-Q filed on 10/31/2013
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2013
Oct. 21, 2013
Document and Entity Information
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2013 
 
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
 
110,044,952 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q3 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
 
 
OPERATING REVENUES
$ 1,152,392 
$ 1,109,475 
$ 2,754,866 
$ 2,608,682 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
350,953 
302,894 
859,216 
783,926 
Operations and maintenance
233,323 
220,729 
685,873 
647,628 
Depreciation and amortization
107,388 
100,353 
317,410 
301,068 
Taxes other than income taxes
43,256 
36,507 
124,091 
120,271 
Other expenses
1,784 
1,022 
5,853 
5,323 
Total
736,704 
661,505 
1,992,443 
1,858,216 
OPERATING INCOME
415,688 
447,970 
762,423 
750,466 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
5,569 
5,708 
18,698 
15,639 
Other income (Note 10)
160 
420 
1,387 
1,357 
Other expense (Note 10)
(7,435)
(5,696)
(13,421)
(12,433)
Total
(1,706)
432 
6,664 
4,563 
INTEREST EXPENSE
 
 
 
 
Interest charges
50,587 
52,242 
151,372 
162,209 
Allowance for borrowed funds used during construction
(3,235)
(3,830)
(10,861)
(10,428)
Total
47,352 
48,412 
140,511 
151,781 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
366,630 
399,990 
628,576 
603,248 
INCOME TAXES
131,912 
147,116 
221,424 
219,160 
INCOME FROM CONTINUING OPERATIONS
234,718 
252,874 
407,152 
384,088 
LOSS FROM DISCONTINUED OPERATIONS
 
 
 
 
Net of income tax benefit of $7 for three months ended September 30, 2012 and $1,047 for nine months ended September 30, 2012
 
(11)
 
(1,595)
NET INCOME
234,718 
252,863 
407,152 
382,493 
Less: Net income attributable to noncontrolling interests (Note 6)
8,555 
8,040 
25,338 
23,582 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
226,163 
244,823 
381,814 
358,911 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
110,009 
109,555 
109,935 
109,449 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
111,053 
110,655 
110,913 
110,420 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Income from continuing operations attributable to common shareholders - basic (in dollars per share)
$ 2.06 
$ 2.23 
$ 3.47 
$ 3.29 
Net income attributable to common shareholders - basic (in dollars per share)
$ 2.06 
$ 2.23 
$ 3.47 
$ 3.28 
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)
$ 2.04 
$ 2.21 
$ 3.44 
$ 3.26 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 2.04 
$ 2.21 
$ 3.44 
$ 3.25 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 0.00 
 
$ 1.09 
$ 1.575 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
 
 
Income from continuing operations, net of tax
226,163 
244,834 
381,814 
360,515 
Discontinued operations, net of tax
 
(11)
 
(1,604)
Net income attributable to common shareholders
$ 226,163 
$ 244,823 
$ 381,814 
$ 358,911 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Income tax benefit on discontinued operations
$ 7 
$ 1,047 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
NET INCOME
$ 234,718 
$ 252,863 
$ 407,152 
$ 382,493 
Derivative instruments:
 
 
 
 
Net unrealized loss, net of tax benefit of $95 and $47 for three months ended September 30, 2013 and 2012 and of $162 and $14,817 for nine months ended September 30, 2013 and 2012
(145)
(72)
(247)
(22,696)
Reclassification of net realized loss, net of tax benefit of $9,348 and $19,543 for three months ended September 30, 2013 and 2012 and $15,471 and $34,361 for nine months ended September 30, 2013 and 2012
14,310 
29,935 
23,685 
52,632 
Pension and other postretirement benefits activity, net of tax (expense) of $(625) and $(640) for three months ended September 30, 2013 and 2012 and $(807) and $(1,797) for nine months ended September 30, 2013 and 2012
957 
980 
1,235 
2,752 
Total other comprehensive income
15,122 
30,843 
24,673 
32,688 
COMPREHENSIVE INCOME
249,840 
283,706 
431,825 
415,181 
Less: Comprehensive income attributable to noncontrolling interests
8,555 
8,040 
25,338 
23,582 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 241,285 
$ 275,666 
$ 406,487 
$ 391,599 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
Net unrealized loss, tax benefit
$ 95 
$ 47 
$ 162 
$ 14,817 
Reclassification of net realized loss, tax benefit
9,348 
19,543 
15,471 
34,361 
Pension and other postretirement benefits activity, tax (expense)
$ (625)
$ (640)
$ (807)
$ (1,797)
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 135,457 
$ 26,202 
Customer and other receivables
427,370 
277,225 
Accrued unbilled revenues
132,555 
94,845 
Allowance for doubtful accounts
(3,768)
(3,340)
Materials and supplies (at average cost)
223,385 
218,096 
Fossil fuel (at average cost)
34,959 
31,334 
Deferred income taxes
87,490 
152,191 
Income tax receivable (Note 5)
133,551 
2,423 
Assets from risk management activities (Note 7)
22,741 
25,699 
Deferred fuel and purchased power regulatory asset (Note 3)
37,383 
72,692 
Other regulatory assets (Note 3)
82,558 
71,257 
Other current assets
36,805 
37,102 
Total current assets
1,350,486 
1,005,726 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 7)
26,046 
35,891 
Nuclear decommissioning trust (Note 13)
612,640 
570,625 
Other assets
60,219 
62,694 
Total investments and other assets
698,905 
669,210 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
14,597,995 
14,346,367 
Accumulated depreciation and amortization
(5,101,498)
(4,929,613)
Net
9,496,497 
9,416,754 
Construction work in progress
605,987 
565,716 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
126,092 
128,995 
Intangible assets, net of accumulated amortization
160,134 
162,150 
Nuclear fuel, net of accumulated amortization
140,356 
122,778 
Total property, plant and equipment
10,529,066 
10,396,393 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,105,882 
1,099,900 
Income tax receivable (Note 5)
 
70,389 
Other
138,332 
137,997 
Total deferred debits
1,244,214 
1,308,286 
TOTAL ASSETS
13,822,671 
13,379,615 
CURRENT LIABILITIES
 
 
Accounts payable
250,023 
221,312 
Accrued taxes (Note 5)
183,858 
124,939 
Accrued interest
45,811 
49,380 
Common dividends payable
 
59,789 
Short-term borrowings
 
92,175 
Current maturities of long-term debt (Note 2)
566,481 
122,828 
Customer deposits
77,254 
79,689 
Liabilities from risk management activities (Note 7)
53,468 
73,741 
Regulatory liabilities (Note 3)
88,409 
88,116 
Other current liabilities
181,639 
171,573 
Total current liabilities
1,446,943 
1,083,542 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
 
 
Long-term debt less current maturities
2,782,901 
3,160,219 
Palo Verde sale leaseback lessor notes less current maturities (Note 6)
37,414 
38,869 
Total long-term debt less current maturities
2,820,315 
3,199,088 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,363,783 
2,151,371 
Regulatory liabilities (Note 3)
798,226 
759,201 
Liability for asset retirements
364,635 
357,097 
Liabilities for pension and other postretirement benefits (Note 4)
939,414 
1,058,755 
Deferred investment tax credit
115,984 
99,819 
Liabilities from risk management activities (Note 7)
67,662 
85,264 
Customer advances
109,667 
109,359 
Coal mine reclamation
114,764 
118,860 
Unrecognized tax benefits (Note 5)
81,797 
71,135 
Other
178,053 
183,835 
Total deferred credits and other
5,133,985 
4,994,696 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY (Note 8)
 
 
Common stock, no par value
2,489,180 
2,466,923 
Treasury stock
(10,079)
(4,211)
Total common stock
2,479,101 
2,462,712 
Retained earnings
1,886,038 
1,624,102 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(63,181)
(64,416)
Derivative instruments
(26,154)
(49,592)
Total accumulated other comprehensive loss
(89,335)
(114,008)
Total shareholders' equity
4,275,804 
3,972,806 
Noncontrolling interests (Note 6)
145,624 
129,483 
Total equity
4,421,428 
4,102,289 
TOTAL LIABILITIES AND EQUITY
$ 13,822,671 
$ 13,379,615 
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical)
Sep. 30, 2013
Dec. 31, 2012
EQUITY (Note 8)
 
 
Common stock, par value
   
   
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 407,152 
$ 382,493 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
377,971 
360,570 
Deferred fuel and purchased power
13,093 
51,533 
Deferred fuel and purchased power amortization
23,158 
(91,894)
Allowance for equity funds used during construction
(18,698)
(15,639)
Deferred income taxes
256,132 
197,527 
Deferred investment tax credit
16,164 
8,974 
Change in derivative instruments fair value
537 
(943)
Changes in current assets and liabilities:
 
 
Customer and other receivables
(178,029)
(76,697)
Accrued unbilled revenues
(37,710)
(11,186)
Materials, supplies and fossil fuel
(8,914)
(23,873)
Income tax receivable
(131,128)
6,466 
Other current assets
(12,246)
(10,035)
Accounts payable
44,704 
(69,776)
Accrued taxes
58,919 
69,899 
Other current liabilities
4,096 
17,071 
Change in margin and collateral accounts - assets
(327)
1,980 
Change in long-term income tax receivable
137,270 
(1,320)
Change in unrecognized tax benefits
(57,585)
(3,554)
Change in other long-term assets
(24,345)
(13,885)
Change in other long-term liabilities
(2,884)
37,181 
Change in margin and collateral accounts - liabilities
15,000 
114,579 
Net cash flow provided by operating activities
882,330 
929,471 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(581,515)
(670,684)
Contributions in aid of construction
34,910 
41,451 
Allowance for borrowed funds used during construction
(10,861)
(10,428)
Proceeds from nuclear decommissioning trust sales
363,944 
295,126 
Investment in nuclear decommissioning trust
(376,881)
(308,063)
Other
(1,553)
(520)
Net cash flow used for investing activities
(571,956)
(653,118)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
136,307 
351,081 
Repayment of long-term debt
(72,777)
(421,703)
Short-term borrowings and payments - net
(92,175)
 
Dividends paid on common stock
(174,485)
(167,074)
Common stock equity issuance
10,396 
9,684 
Distributions to noncontrolling interests
(9,197)
(2,630)
Other
812 
185 
Net cash flow used for financing activities
(201,119)
(230,457)
NET INCREASE IN CASH AND CASH EQUIVALENTS
109,255 
45,896 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
26,202 
33,583 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$ 135,457 
$ 79,479 
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 and El Dorado Investment Company (“El Dorado”) and formerly SunCor Development Company (“SunCor”).  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 6 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 2012 Form 10-K, with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.

 

The following tables show the impact of the reclassifications to prior year (previously reported) amounts of the deferred investment tax credit and income tax receivables which have become more material in 2013 (dollars in thousands):

 

Balance Sheets - December 31, 2012

 

As
previously
reported

 

Reclassifications

 

Amount
reported after
reclassifications

 

 

 

 

 

 

 

 

 

Deferred investment tax credit

 

$

 

$

99,819

 

$

99,819

 

Deferred credits — other

 

283,654

 

(99,819

)

183,835

 

 

Statement of Cash Flows for the Nine
Months Ended September 30, 2012

 

As
previously
reported

 

Reclassifications

 

Amount
reported after
reclassifications

 

 

 

 

 

 

 

 

 

Cash Flows from Operating Activities

 

 

 

 

 

 

 

Deferred income taxes

 

$

206,501

 

$

(8,974

)

$

197,527

 

Deferred investment tax credit

 

 

8,974

 

8,974

 

Income tax receivable

 

 

6,466

 

6,466

 

Accrued taxes

 

76,365

 

(6,466

)

69,899

 

Change in long-term income tax receivable

 

 

(1,320

)

(1,320

)

Change in other long-term assets

 

(15,205

)

1,320

 

(13,885

)

 

Supplemental Cash Flow Information

 

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):

 

 

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

Cash paid during the period for:

 

 

 

 

 

Income taxes, net of (refunds)

 

$

3,412

 

$

(651

)

Interest, net of amounts capitalized

 

141,047

 

152,582

 

Significant non-cash investing and financing activities:

 

 

 

 

 

Accrued capital expenditures

 

$

11,377

 

$

11,281

 

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 September 30, 2013, 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 September 30, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding, and no commercial paper borrowings.

 

APS

 

On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.

 

On April 9, 2013, APS replaced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility.  The new revolving credit facility terminates in April 2018.

 

On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029.  On May 28, 2013, we remarketed the bonds.  The interest rate for these bonds was set to a new term rate.  The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018.  During this time, the bonds will bear interest at a rate of 1.75% per annum.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2013 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.

 

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029.  These bonds were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.

 

At September 30, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit 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 September 30, 2013, APS had no commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.

 

On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012.

 

See “Financial Assurances” in Note 9 for a discussion of APS’s separate 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 12 for a 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
September 30, 2013

 

As of
December 31, 2012

 

 

 

Carrying
Amount

 

Fair Value

 

Carrying
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Pinnacle West

 

$

125

 

$

125

 

$

125

 

$

125

 

APS

 

3,262

 

3,538

 

3,197

 

3,750

 

Total

 

$

3,387

 

$

3,663

 

$

3,322

 

$

3,875

 

 

Debt Provisions

 

An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At September 30, 2013, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.4 billion, and total capitalization was approximately $7.6 billion.  APS would be prohibited from paying dividends if payment would reduce its total shareholder equity below approximately $3.0 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 have increased the average retail customer bill approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the Settlement Agreement without material modifications.

 

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 for fuel and purchased power costs (“Base Fuel Rate”) from $0.03757 to $0.03207 per kilowatt hour (“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 up to approximately $5 million in revenues annually;

 

·                                          Modifications to the Power Supply Adjustor (“PSA”), including the elimination of the 90/10 sharing provision;

 

·                                          A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge (“DSMAC”) to recoup capital expenditures not required under the terms of the 2008 rate case settlement agreement discussed below;

 

·                                          Allowing a negative credit that existed in the PSA rate 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.

 

The Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2008 rate case settlement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.

 

2008 General Retail Rate Case On-Going 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 contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

 

·                                          A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

 

·                                          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 through 2012 and its use of renewable energy through 2015, 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 December 14, 2011, the ACC voted to approve APS’s 2012 RES plan covering the 2012-2016 timeframe and authorized a total 2012 RES budget of $110 million.  On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requested 2013 RES funding of between $97 million and $107 million.  In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan.  That budget included $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for new commercial distributed energy production-based incentives beyond those for previously approved programs.  The ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  In those proceedings, the ACC staff proposed a process whereby if a customer installs distributed generation without an incentive, the customer keeps the renewable energy credits generated and the RES distributed generation requirement is adjusted downward to reflect how much load is being served by renewable generation.  APS has endorsed the ACC staff’s proposed solution.  Finally, the ACC authorized an APS-led multi-session technical conference to consider APS’s net metering policy and the cost and benefits of distributed energy.  The multi-session technical conference concluded on May 28, 2013.

 

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules.  In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either:  (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price.  APS also proposed that the ACC:  (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.  In its September 30, 2013 report, the ACC staff recognized that net metering shifts costs from solar customers to non-solar customers.  The staff recommended that the ACC wait until APS’s next rate case to address the issue.  As an alternative, the ACC staff recommended that the ACC assess one of two modest charges on new solar customers with a mechanism to return all incremental revenue collected from such charges to customers.

 

On July 12, 2013, APS filed its annual RES implementation plan covering the 2014-2018 timeframe.  The plan requests a budget for 2014 of approximately $143 million.  The plan does not propose any new programs.  Rather, the plan requests the funding necessary to fulfill previously approved projects and commitments which are needed to comply with the RES targets and APS’s obligations under its 2008 rate case settlement agreement approved by the ACC, including the remaining 50 megawatts (“MW”) of the AZ Sun Program.  AZ Sun is a program that contemplates the development of photovoltaic solar plants which APS owns or will own.  On September 30, 2013, the ACC staff issued a report recommending approval of APS’s plan and proposed budget.

 

Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC.

 

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Standards, which became effective January 1, 2011.  The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% 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 (2.75% of total energy resources for the same two-year period).  The ACC issued an order on April 4, 2012, approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs.  This amount will be recovered by the then existing DSMAC over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).

 

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.  APS expects to receive a decision from the ACC in late 2013 or early 2014.

 

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards (including cost recovery methodology, incentives, and the determination of cost effectiveness) should be modified or abolished.

 

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 for 2013 and 2012 (dollars in millions):

 

 

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

Beginning balance

 

$

73

 

$

28

 

Deferred fuel and purchased power costs — current period

 

(13

)

(52

)

Amounts (collected from) credited to customers

 

(23

)

92

 

Ending balance

 

$

37

 

$

68

 

 

The PSA rate for the PSA year beginning February 1, 2013 is $0.0013 per kWh as compared to ($0.0042) per kWh for the prior year.  This represents a $0.0055 per kWh increase over the 2012 PSA charge.  This new rate is comprised of a forward component of ($0.0010) per kWh and a historical component of $0.0023 per kWh.  The Settlement Agreement allowed APS to exceed the $0.004 per kWh cap to PSA rate changes in this instance.  Any uncollected (overcollected) deferrals during the 2013 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2014.

 

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In 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 was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 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- or under-collected amounts.

 

Effective June 1, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula.

 

Effective June 1, 2013, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $26 million for the twelve-month period beginning June 1, 2013 in accordance with the FERC-approved formula.  Pursuant to the Settlement Agreement (discussed above), an adjustment to APS’s retail rates to recover the FERC-approved transmission charges went into effect automatically on June 1, 2013.

 

As part of APS’s proposed acquisition of Southern California Edison’s (“SCE”) interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing transmission agreement between the parties that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California.  On May 1, 2013, APS submitted a request with FERC seeking authorization to cancel the transmission agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 10-year period.  On September 13, 2013, FERC issued an Order accepting the notice of cancellation, but denying APS’s request for rate recovery of the costs associated with the cancellation.  In accordance with its termination agreement with SCE (the “Termination Agreement”), APS believes that the denial by FERC of such rate recovery constitutes the failure of a condition that relieves APS of its obligations under the Termination Agreement.  The parties are in discussions concerning this matter.  If the matter is not resolved by negotiation, the Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter.

 

Lost Fixed Cost Recovery (“LFCR”) Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as roof-top solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the recent rate case and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques.

 

APS filed its first LFCR adjustment on January 15, 2013 and will file for its LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved an LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the Settlement Agreement went into effect on July 1, 2012.

 

Deregulation

 

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.

 

Regulatory Assets and Liabilities

 

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

 

 

 

Remaining
Amortization 

 

September 30, 2013

 

December 31, 2012

 

 

 

Period

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Pension and other postretirement benefits

 

 

(a)

$

 

$

754

 

$

 

$

780

 

Income taxes — allowance for equity funds used during construction

 

2043

 

4

 

105

 

4

 

92

 

Deferred fuel and purchased power — mark-to-market (Note 7)

 

2016

 

15

 

24

 

19

 

21

 

Transmission vegetation management

 

2016

 

9

 

16

 

9

 

23

 

Coal reclamation

 

2038

 

8

 

20

 

8

 

24

 

Palo Verde VIEs (Note 6)

 

2046

 

 

40

 

 

38

 

Deferred compensation

 

2036

 

 

36

 

 

34

 

Deferred fuel and purchased power (b) (c)

 

2013

 

37

 

 

73

 

 

Retired power plant costs

 

2020

 

3

 

19

 

 

 

Tax expense of Medicare subsidy

 

2024

 

2

 

15

 

2

 

17

 

Loss on reacquired debt

 

2034

 

1

 

17

 

2

 

18

 

Income taxes — investment tax credit basis adjustment

 

2042

 

1

 

30

 

1

 

26

 

Pension and other postretirement benefits deferral

 

2015

 

8

 

6

 

8

 

13

 

Lost fixed cost recovery (b)

 

2014

 

19

 

 

7

 

 

Transmission cost adjustor (b)

 

2014

 

12

 

2

 

10

 

 

Other

 

Various

 

1

 

22

 

1

 

14

 

Total regulatory assets (d)

 

 

 

$

120

 

$

1,106

 

$

144

 

$

1,100

 

 

 

(a)                                 This asset represents the future recovery of under-funded pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income (“OCI”) and result in lower future revenues.

(b)                                 See “Cost Recovery Mechanisms” discussion above.

(c)                                  Subject to a carrying charge.

(d)                                 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):

 

 

 

 

Remaining
Amortization

 

September 30, 2013

 

December 31, 2012

 

 

 

Period

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Removal costs

 

 

(a)

$

26

 

$

311

 

$

27

 

$

321

 

Asset retirement obligations

 

 

(a)

 

272

 

 

256

 

Renewable energy standard (b)

 

2014

 

27

 

22

 

43

 

 

Income taxes — change in rates

 

2042

 

 

68

 

 

66

 

Spent nuclear fuel

 

2047

 

5

 

37

 

10

 

36

 

Deferred gains on utility property

 

2019

 

2

 

11

 

2

 

12

 

Income taxes — deferred investment tax credit

 

2042

 

2

 

60

 

2

 

52

 

Demand side management (b)

 

2014

 

26

 

 

4

 

 

Other

 

Various

 

 

17

 

 

16

 

Total regulatory liabilities

 

 

 

$

88

 

$

798

 

$

88

 

$

759

 

 

 

(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 were deferred through June 30, 2012 as a regulatory asset for future recovery, pursuant to an ACC regulatory order.  We deferred pension and other postretirement benefit costs of approximately $14 million in 2012.  Pursuant to an ACC regulatory order, we began amortizing the regulatory asset in July 2012.  We amortized approximately $2 million for the three months ended September 30, 2013, and 2012, and approximately $6 million and $2 million for the nine months ended September 30, 2013 and 2012, respectively.  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 or amortized to the regulatory asset) (dollars in millions):

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

2013

 

2012

 

2013

 

2012

 

Service cost — benefits earned during the period

 

$

16

 

$

16

 

$

48

 

$

48

 

$

6

 

$

7

 

$

18

 

$

20

 

Interest cost on benefit obligation

 

28

 

30

 

84

 

90

 

10

 

12

 

31

 

35

 

Expected return on plan assets

 

(36

)

(35

)

(110

)

(106

)

(11

)

(12

)

(34

)

(34

)

Amortization of:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prior service cost

 

 

 

1

 

1

 

 

 

 

 

Net actuarial loss

 

10

 

11

 

30

 

33

 

3

 

5

 

8

 

15

 

Net periodic benefit cost

 

$

18

 

$

22

 

$

53

 

$

66

 

$

8

 

$

12

 

$

23

 

$

36

 

Portion of cost charged to expense

 

$

10

 

$

12

 

$

29

 

$

25

 

$

5

 

$

7

 

$

14

 

$

13

 

 

Contributions

 

We have made voluntary contributions of $141 million to our pension plan in 2013.  The minimum contributions for the pension plan due in 2013, 2014, and 2015 under the recently enacted Moving Ahead for Progress in the 21st Century Act (MAP-21) are estimated to be zero, $89 million, and $112 million, respectively.  We expect to make contributions to the pension plan up to approximately $175 million each year in 2014 and 2015.  We have contributed $11 million to our other postretirement benefit plans in 2013.  The total contributions to our other postretirement benefit plans are expected to be approximately $14 million in 2013 and approximately $20 million each year in 2014 and 2015.

Income Taxes
Income Taxes

5.                                      Income Taxes

 

The $70 million long-term income tax receivable on the Condensed Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  The $137 million anticipated refund is expected to be received within the next twelve months and has been reclassified to current income tax receivable as of September 30, 2013.

 

Finalization of the current IRS examination of tax returns for the years ended December 31, 2008 and 2009 is likely to occur within the next twelve months.  As a result, the $137 million anticipated refund has been reduced by approximately $4 million to reflect the likely ultimate outcome of this examination.  Additionally, it is possible that uncertain tax positions could decrease by approximately $35 million.  This decrease would be materially offset by an increase in deferred tax liabilities.

 

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS, resulting in a cumulative effect adjustment.  To account for the adoption of these regulations, for the quarter ended September 30, 2013, plant-related long-term deferred tax liabilities decreased by $80 million, with the offsetting decrease to current deferred income tax assets. Prior to the issuance of these regulations, this $80 million would have been repaid over 20 years through lower tax depreciation deductions.

 

Net Income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 6).  As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.

 

The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions making qualified property placed into service in 2013 eligible for 50% bonus depreciation for federal income tax purposes.  Full recognition of the cash benefit of this provision delayed realization of approximately $78 million in federal general business income tax credit carryforwards which were classified as current deferred income taxes as of December 31, 2012.  However, as of September 30, 2013, the $78 million in federal general business tax credit carryforwards are expected to be realized within the next twelve months.

 

As of September 30, 2013, 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 2008.

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

6.                                      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 2013 to 2015 related to these leases.  The lease agreements include fixed rate renewal periods, which gives 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.  Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

 

On December 31, 2012, APS notified the lessor trust entities that APS would retain the assets beyond 2015 by either exercising the fixed rate lease renewals or by purchasing the assets.  If APS elects to purchase the assets, the purchase price will be based on the fair market value of the assets at the end of 2015.  If APS elects to extend the leases, we will be required to make payments beginning in 2016 of approximately $23 million annually.  The length of the lease extensions is unknown at this time as it must be determined through an appraisal process.  APS must give notice to the lessor trusts by June 30, 2014 notifying them which of these two options (lease renewal or purchasing the assets) it will exercise.  The December 31, 2012 notification does not impact APS’s consolidation of the VIEs, as APS continues to be deemed the primary beneficiary of 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 and nine months ended September 30, 2013 of $9 million and $25 million, respectively, and for the three and nine months ended September 30, 2012 of $8 million and $24 million, respectively, entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders remains the same.  Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

 

Our Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):

 

 

 

September 30,
2013

 

December 31,
2012

 

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

 

$

126

 

$

129

 

Current maturities of long-term debt

 

20

 

27

 

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

 

37

 

39

 

Equity — Noncontrolling interests

 

146

 

129

 

 

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 September 30, 2013, APS would have been required to pay the noncontrolling equity participants approximately $142 million and assume $57 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

7.                                      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 may be 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, these instruments have not been 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.

 

On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as accounting hedges.  This discontinuation is due to changes in PSA recovery (see Note 3), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts.  For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through other comprehensive income (“OCI”), but are deferred through the PSA.  The amounts previously recorded in accumulated OCI (“AOCI”) relating to these instruments will remain in AOCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur.  Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.

 

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 12 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 purchases and normal 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 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 cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.

 

Prior to the Settlement Agreement, for its regulated operations, APS deferred 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.  Due to the Settlement Agreement, for its regulated operations, APS now defers for future rate treatment 100% of the unrealized gains and losses for delivery periods after June 30, 2012 on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

 

As of September 30, 2013, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

 

Commodity

 

Quantity

 

Power

 

6,498

 

gigawatt hours

 

Gas

 

112

 

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 (dollars in thousands):

 

 

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Commodity Contracts

 

Financial Statement Location

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss recognized in OCI on derivative instruments (effective portion)

 

Other comprehensive income (loss) — derivative instruments

 

$

(240

)

$

(119

)

$

(409

)

$

(37,513

)

Loss reclassified from AOCI into income (effective portion realized) (a)

 

Fuel and purchased power (b)

 

(23,658

)

(49,478

)

(39,156

)

(86,993

)

Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)

 

Fuel and purchased power (b)

 

 

 

 

117

 

 

 

(a)         During the three and nine months ended September 30, 2013 and three months ended September 30, 2012, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.  During the nine months ended September 30, 2012, we had $1.8 million of losses reclassified from AOCI to earnings related to discontinued cash flow hedges.

 

(b)         Amounts are before the effect of PSA deferrals.

 

During the next twelve months, we estimate that a net loss of $23 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

 

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):

 

 

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Commodity Contracts

 

Financial Statement Location

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

 

 

Net gain recognized in income

 

Operating revenues (a)

 

$

196

 

$

258

 

$

400

 

$

19

 

 

 

 

 

 

 

 

 

 

 

 

 

Net gain (loss) recognized in income

 

Fuel and purchased power expense (a)

 

(1,341

)

12,870

 

(11,750

)

13,860

 

Total

 

 

 

$

(1,145

)

$

13,128

 

$

(11,350

)

$

13,879

 

 

 

(a)         Amounts are before the effect of PSA deferrals.

 

Derivative Instruments in the Condensed Consolidated Balance Sheets

 

Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and in the event of a default would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.

 

We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.

 

The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012, include gross liabilities of $5 million of derivative instruments designated as hedging instruments.

 

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of September 30, 2013 and December 31, 2012.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

 

As of September 30, 2013:
(dollars in thousands)

 

Gross 
Recognized 
Derivatives

(a)

 

Amounts 
Offset
(b)

 

Net
Recognized
Derivatives

 

Other
(c)

 

Amount 
Reported on 
Balance Sheet

 

Current Assets

 

$

32,201

 

$

(9,605

)

$

22,596

 

$

145

 

$

22,741

 

Investments and Other Assets

 

27,905

 

(1,859

)

26,046

 

 

26,046

 

Total Assets

 

60,106

 

(11,464

)

48,642

 

145

 

48,787

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(66,680

)

32,675

 

(34,005

)

(19,463

)

(53,468

)

Deferred Credits and Other

 

(74,751

)

7,089

 

(67,662

)

 

(67,662

)

Total Liabilities

 

(141,431

)

39,764

 

(101,667

)

(19,463

)

(121,130

)

Total

 

$

(81,325

)

$

28,300

 

$

(53,025

)

$

(19,318

)

$

(72,343

)

 

 

(a)         All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)         Includes cash collateral provided to counterparties of $28,300.

(c)          Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $19,463, and cash margin provided to counterparties of $145.

 

As of December 31, 2012:
(dollars in thousands) 

 

Gross
Recognized
Derivatives
(a)

 

Amounts
Offset
 (b)

 

Net
Recognized
Derivatives

 

Other
(c)

 

Amount
Reported on
Balance Sheet

 

Current Assets

 

$

42,495

 

$

(17,797

)

$

24,698

 

$

1,001

 

$

25,699

 

Investments and Other Assets

 

41,563

 

(5,672

)

35,891

 

 

35,891

 

Total Assets

 

84,058

 

(23,469

)

60,589

 

1,001

 

61,590

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(105,324

)

57,046

 

(48,278

)

(25,463

)

(73,741

)

Deferred Credits and Other

 

(100,986

)

15,722

 

(85,264

)

 

(85,264

)

Total Liabilities

 

(206,310

)

72,768

 

(133,542

)

(25,463

)

(159,005

)

Total

 

$

(122,252

)

$

49,299

 

$

(72,953

)

$

(24,462

)

$

(97,415

)

 

 

(a)         All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)         Includes cash collateral provided to counterparties of $49,299.

(c)          Represents cash collateral relating to non-derivative instruments or derivatives qualifying for scope exceptions.  Includes cash collateral provided to counterparties of $1,001, and cash collateral received from counterparties of $25,463.  This amount is not subject to offsetting.

 

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 90% of Pinnacle West’s $49 million of risk management assets as of September 30, 2013.  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 a subjective event and/or condition.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

 

The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2013 (dollars in millions):

 

 

 

September 30,
2013

 

Aggregate Fair Value of Derivative Instruments in a Net Liability Position

 

$

141

 

Cash Collateral Posted

 

28

 

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

 

88

 

 

 

(a)         This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details 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 $175 million if our debt credit ratings were to fall below investment grade.

Changes in Equity
Changes in Equity

8.                                      Changes in Equity

 

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):

 

 

 

Three Months Ended September 30, 2013

 

Three Months Ended September 30, 2012

 

 

 

Common 
Shareholders

 

Noncontrolling 
Interests

 

Total

 

Common 
Shareholders

 

Noncontrolling 
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, July 1

 

$

4,032,165

 

$

137,069

 

$

4,169,234

 

$

3,778,035

 

$

121,302

 

$

3,899,337

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

226,163

 

8,555

 

234,718

 

244,823

 

8,040

 

252,863

 

Other comprehensive income

 

15,122

 

 

15,122

 

30,843

 

 

30,843

 

Total comprehensive income

 

241,285

 

8,555

 

249,840

 

275,666

 

8,040

 

283,706

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

2,331

 

 

2,331

 

2,365

 

 

2,365

 

Reissuance of treasury stock — net

 

37

 

 

37

 

(82

)

 

(82

)

Other (primarily stock compensation)

 

(22

)

 

(22

)

258

 

 

258

 

Dividends on common stock

 

8

 

 

8

 

 

 

 

Ending balance, September 30

 

$

4,275,804

 

$

145,624

 

$

4,421,428

 

$

4,056,242

 

$

129,342

 

$

4,185,584

 

 

 

 

Nine Months Ended September 30, 2013

 

Nine Months Ended September 30, 2012

 

 

 

Common 
Shareholders

 

Noncontrolling
Interests

 

Total

 

Common 
Shareholders

 

Noncontrolling 
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, January 1

 

$

3,972,806

 

$

129,483

 

$

4,102,289

 

$

3,821,850

 

$

108,736

 

$

3,930,586

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

381,814

 

25,338

 

407,152

 

358,911

 

23,582

 

382,493

 

Other comprehensive income

 

24,673

 

 

24,673

 

32,688

 

 

32,688

 

Total comprehensive income

 

406,487

 

25,338

 

431,825

 

391,599

 

23,582

 

415,181

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

7,268

 

 

7,268

 

7,590

 

 

7,590

 

Reissuance (purchase) of treasury stock - net

 

(5,868

)

 

(5,868

)

3,277

 

 

3,277

 

Other (primarily stock compensation)

 

14,988

 

 

14,988

 

4,270

 

 

4,270

 

Dividends on common stock

 

(119,877

)

 

(119,877

)

(172,344

)

 

(172,344

)

Net capital activities by noncontrolling interests

 

 

(9,197

)

(9,197

)

 

(2,976

)

(2,976

)

Ending balance, September 30

 

$

4,275,804

 

$

145,624

 

$

4,421,428

 

$

4,056,242

 

$

129,342

 

$

4,185,584

 

Commitments and Contingencies
Commitments and Contingencies

9.                                      Commitments and Contingencies

 

Palo Verde Nuclear Generating Station

 

Spent Nuclear Fuel and Waste Disposal

 

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the United States Department of Energy (“DOE”) in the United States Court of Federal Claims.  The lawsuit seeks to recover APS’s damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  Activities in this legal proceeding are currently limited to review of supporting information for APS’s claim by the Government.

 

APS currently estimates it will incur $122 million 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 September 30, 2013, APS had a regulatory liability of $42 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

 

Nuclear Insurance

 

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.6 billion per occurrence.  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 $13.2 billion of liability coverage 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 $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation.  Based on APS’s interest in the three Palo Verde units, APS’s maximum potential retrospective assessment per incident for all three units is approximately $111.1 million, with an annual payment limitation of approximately $16.4 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”).  Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses site-wide has been imposed on the NEIL property policies.  Effective April 1, 2013, a sublimit of $327.6 million per unit has been imposed on the non-nuclear losses covered by the NEIL accidental outage policy, potentially subject to further limitations.  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, sublimits and exclusions.

 

Contractual Obligations

 

As of September 30, 2013, our contractual obligations for fuel and purchased power commitments decreased approximately $300 million from December 31, 2012, as discussed in the 2012 Form 10-K.  As of September 30, 2013, the updated contractual obligations related to our fuel and purchased power obligations are as follows (dollars in millions):

 

 

 

2013

 

2014

 

2015

 

2016

 

2017

 

Thereafter

 

Total

 

Fuel and Purchased Power

 

$

108

 

$

576

 

$

549

 

$

516

 

$

441

 

$

6,399

 

$

8,589

 

 

For additional information regarding contractual obligations, see information provided in our 2012 Form 10-K.

 

Superfund-Related Matters

 

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 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 EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with 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 $2 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 expenditures related to this matter cannot be reasonably estimated.

 

On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

 

Southwest Power Outage

 

Regulatory.  On September 8, 2011 at approximately 3:30 PM, 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.  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 9:15 PM on September 8.  Service to customers affected by the wider regional outages was restored by approximately 3:25 AM on September 9.

 

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 (the “Joint 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 an assessment of responsibility of the parties involved.  APS continues to analyze business practices and procedures related to the September 8 events.

 

APS cannot predict the timing, results or potential impacts of enforcement actions that may be brought against APS relating to the September 8 events, or any 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.

 

Litigation.  On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service.  APS and Pinnacle West intend to file a motion to dismiss the complaint.

 

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 New Source Review (“NSR”) 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 NSR 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.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss without risk of default.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

 

Environmental Matters

 

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“CCR”).  These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.  Associated capital expenditures or operating costs could be material.  APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery.  The following proposed and final rules involve material compliance costs to APS.

 

Regional Haze Rules.  APS has received the final rulemaking imposing new requirements on Four Corners and the Cholla Power Plant (“Cholla”) and is currently awaiting a final rulemaking from EPA that could impose new requirements on the Navajo Generating Station (“Navajo Plant”).  EPA and Arizona Department of Environmental Quality (“ADEQ”) will require these plants to install pollution control equipment that constitutes the “best available retrofit technology” (“BART”) to lessen the impacts of emissions on visibility surrounding the plants.  Based on EPA’s final standards, APS’s share of its total costs for Four Corners (assuming the consummation of its purchase of SCE’s interest in Units 4 and 5 and subsequent shut down of Units 1-3) could be approximately $300 million.  APS’s share of costs for upgrades at Navajo, based on EPA’s Federal Implementation Plan (“FIP”) proposal, could be up to approximately $200 million.  APS has filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, will require installation of controls with a cost to APS of approximately $200 million.

 

Mercury and Other Hazardous Air Pollutants.  In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants.  APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $120 million for Cholla Units 1-3.  Estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3.  No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  Salt River Project Agricultural Improvement and Power District (“SRP”), the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.

 

Other future environmental rules that could involve material compliance costs include those related to cooling water intake structures, coal combustion waste, effluent limitations, ozone national ambient air quality, greenhouse gas emissions and other rules or matters involving the Clean Air Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.  The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.  APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

 

Regional Haze Rules — Cholla

 

APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan (“SIP”) and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program.  Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit.  In addition, on February 4, 2013, APS filed a Petition for Reconsideration and Stay of the final BART rule with EPA.  On March 22, 2013, APS filed a motion with the court to suspend the compliance deadlines under the BART rule until the court rules on the matter.  The State of Arizona and three other Arizona utilities also filed similar petitions and motions.  On September 30, 2013, the court issued an order denying these motions to suspend the compliance deadline.

 

New Mexico Tax Matter

 

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”).  APS’s share of the Assessment is approximately $12 million.  For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013.  The New Mexico Taxation and Revenue Department denied the refund claim.  Prior to year end, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, intend to file a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  APS believes the Assessment and the refund claim denial are without merit, but cannot predict the timing or outcome of this litigation.

 

Financial Assurances

 

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At September 30, 2013, approximately $76 million of letters of credit were outstanding to support existing 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.  One of these letters of credit expires in 2015 and two expire in 2016.  APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire on December 31, 2015, and totaled approximately $32 million at September 30, 2013.  Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements, including certain natural gas tolling contracts entered into with third parties.  At September 30, 2013, $60 million of such letters of credit were outstanding that will expire in 2014 and 2015.

 

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.

 

Pinnacle West has issued parental guarantees and surety bonds for APS which were not material at September 30, 2013.

Other Income and Other Expense
Other Income and Other Expense

10.                               Other Income and Other Expense

 

The following table provides detail of other income and other expense for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Other income:

 

 

 

 

 

 

 

 

 

Interest income

 

$

116

 

$

307

 

$

1,291

 

$

1,018

 

Miscellaneous

 

44

 

113

 

96

 

339

 

Total other income

 

$

160

 

$

420

 

$

1,387

 

$

1,357

 

 

 

 

 

 

 

 

 

 

 

Other expense:

 

 

 

 

 

 

 

 

 

Non-operating costs

 

$

(2,028

)

$

(1,645

)

$

(5,951

)

$

(5,885

)

Investment losses — net

 

(3,435

)

(2,254

)

(3,643

)

(2,366

)

Miscellaneous

 

(1,972

)

(1,797

)

(3,827

)

(4,182

)

Total other expense

 

$

(7,435

)

$

(5,696

)

$

(13,421

)

$

(12,433

)

 

Earnings Per Share
Earnings Per Share

11.                               Earnings Per Share

 

The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2013 and 2012:

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Basic earnings per share:

 

 

 

 

 

 

 

 

 

Income from continuing operations attributable to common shareholders

 

$

2.06

 

$

2.23

 

$

3.47

 

$

3.29

 

Loss from discontinued operations

 

 

 

 

(0.01

)

Earnings per share — basic

 

$

2.06

 

$

2.23

 

$

3.47

 

$

3.28

 

 

 

 

 

 

 

 

 

 

 

Diluted earnings per share:

 

 

 

 

 

 

 

 

 

Income from continuing operations attributable to common shareholders

 

$

2.04

 

$

2.21

 

$

3.44

 

$

3.26

 

Loss from discontinued operations

 

 

 

 

(0.01

)

Earnings per share — diluted

 

$

2.04

 

$

2.21

 

$

3.44

 

$

3.25

 

 

Performance shares and restricted stock units (which are contingently issuable) increased the weighted average common shares outstanding by approximately 1,044,000 shares and 1,100,000 shares for the three months ended September 30, 2013 and 2012, respectively, and by approximately 978,000 shares and 971,000 shares for the nine months ended September 30, 2013 and 2012, respectively.

 

For the three and nine months ended September 30, 2013 and 2012, there were no common stock options that were excluded from the computation of diluted earnings per share as a result of the options’ exercise prices being greater than the average market price of the common shares.

 

Fair Value Measurements
Fair Value Measurements

12.                               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 United States 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 value (“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 inputs and 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 activity, 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 2012 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 our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  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.

 

Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies.  We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures.  The risk control function reports to the chief financial officer’s organization.

 

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 the concept of NAV, which is a value 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 United States government fixed income securities.  We may transact in this commingled fund on a daily basis at the NAV.

 

Fixed income securities issued by the United States 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 curves and spreads relative to such yield 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 have internal control procedures designed to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.  See Note 13 for additional discussion about our nuclear decommissioning trust.

 

Fair Value Tables

 

The following table presents the fair value at September 30, 2013 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
September 30,
2013

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Risk management activities — derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity Contracts

 

$

 

$

12

 

$

48

 

$

(11

)(b)

$

49

 

Nuclear decommissioning trust:

 

 

 

 

 

 

 

 

 

 

 

U.S. commingled equity funds

 

 

245

 

 

 

245

 

Fixed income securities:

 

 

 

 

 

 

 

 

 

 

 

U.S. Treasury

 

109

 

 

 

 

109

 

Cash and cash equivalent funds

 

 

13

 

 

(3

)(c)

10

 

Corporate debt

 

 

83

 

 

 

83

 

Mortgage-backed securities

 

 

82

 

 

 

82

 

Municipality bonds

 

 

71

 

 

 

71

 

Other

 

 

13

 

 

 

13

 

Subtotal nuclear decommissioning trust

 

109

 

507

 

 

(3

)

613

 

Total

 

$

109

 

$

519

 

$

48

 

$

(14

)

$

662

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

Risk management activities — derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

 

$

(49

)

$

(92

)

$

20

(b)

$

(121

)

 

 

(a)             &