PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/2/2014
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2014
Apr. 25, 2014
Document and Entity Information
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Mar. 31, 2014 
 
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
 
110,357,309 
Document Fiscal Year Focus
2014 
 
Document Fiscal Period Focus
Q1 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
OPERATING REVENUES
$ 686,251 
$ 686,652 
OPERATING EXPENSES
 
 
Fuel and purchased power
249,786 
230,679 
Operations and maintenance
212,882 
223,250 
Depreciation and amortization
101,772 
103,730 
Taxes other than income taxes
45,845 
40,021 
Other expenses
796 
2,049 
Total
611,081 
599,729 
OPERATING INCOME
75,170 
86,923 
OTHER INCOME (DEDUCTIONS)
 
 
Allowance for equity funds used during construction
7,442 
6,864 
Other income (Note 10)
2,367 
758 
Other expense (Note 10)
(4,684)
(3,752)
Total
5,125 
3,870 
INTEREST EXPENSE
 
 
Interest charges
52,969 
49,478 
Allowance for borrowed funds used during construction
(3,770)
(3,990)
Total
49,199 
45,488 
INCOME BEFORE INCOME TAXES
31,096 
45,305 
INCOME TAXES
6,405 
12,469 
NET INCOME
24,691 
32,836 
Less: Net income attributable to noncontrolling interests (Note 6)
8,925 
8,392 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 15,766 
$ 24,444 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
110,257 
109,832 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
110,888 
110,835 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.14 
$ 0.22 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 0.14 
$ 0.22 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
$ 24,691 
$ 32,836 
Derivative instruments:
 
 
Net unrealized gain (loss), net of tax benefit (expense) of $(599) and $(38)
(422)
58 
Reclassification of net realized loss, net of tax benefit of $1,323 and $3,300
3,116 
5,053 
Pension and other postretirement benefits activity, net of tax expense of $718 and $631
457 
966 
Total other comprehensive income
3,151 
6,077 
COMPREHENSIVE INCOME
27,842 
38,913 
Less: Comprehensive income attributable to noncontrolling interests
8,925 
8,392 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 18,917 
$ 30,521 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Net unrealized loss, tax benefit (expense)
$ (599)
$ (38)
Reclassification of net realized loss, tax benefit
1,323 
3,300 
Pension and other postretirement benefits activity, tax expense
$ 718 
$ 631 
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2014
Dec. 31, 2013
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 103,421 
$ 9,526 
Customer and other receivables
245,884 
299,904 
Accrued unbilled revenues
88,907 
96,796 
Allowance for doubtful accounts
(2,504)
(3,203)
Materials and supplies (at average cost)
223,401 
221,682 
Fossil fuel (at average cost)
36,496 
38,028 
Deferred income taxes
58,630 
91,152 
Income tax receivable (Note 5)
4,647 
135,517 
Assets from risk management activities (Note 7)
16,951 
17,169 
Deferred fuel and purchased power regulatory asset (Note 3)
 
20,755 
Other regulatory assets (Note 3)
76,317 
76,388 
Other current assets
45,780 
39,895 
Total current assets
897,930 
1,043,609 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 7)
21,626 
23,815 
Nuclear decommissioning trust (Note 13)
657,862 
642,007 
Other assets
60,753 
60,875 
Total investments and other assets
740,241 
726,697 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
15,256,945 
15,200,464 
Accumulated depreciation and amortization
(5,360,781)
(5,300,219)
Net
9,896,164 
9,900,245 
Construction work in progress
646,236 
581,369 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
124,157 
125,125 
Intangible assets, net of accumulated amortization
144,446 
157,689 
Nuclear fuel, net of accumulated amortization
144,048 
124,557 
Total property, plant and equipment
10,955,051 
10,888,985 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
719,596 
711,712 
Other
137,979 
137,683 
Total deferred debits
857,575 
849,395 
TOTAL ASSETS
13,450,797 
13,508,686 
CURRENT LIABILITIES
 
 
Accounts payable
224,820 
284,516 
Accrued taxes (Note 5)
179,137 
130,998 
Accrued interest
47,392 
48,351 
Common dividends payable
 
62,528 
Short-term borrowings (Note 2)
9,500 
153,125 
Current maturities of long-term debt (Note 2)
540,424 
540,424 
Customer deposits
75,999 
76,101 
Liabilities from risk management activities (Note 7)
19,907 
31,892 
Liabilities for asset retirements
25,536 
32,896 
Deferred fuel and purchased power regulatory liability (Note 3)
18,897 
 
Other regulatory liabilities (Note 3)
116,903 
99,273 
Other current liabilities
136,128 
158,540 
Total current liabilities
1,394,643 
1,618,644 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
3,045,614 
2,796,465 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,359,689 
2,351,882 
Regulatory liabilities (Note 3)
783,702 
801,297 
Liabilities for asset retirements
344,708 
313,833 
Liabilities for pension and other postretirement benefits (Note 4)
442,136 
513,628 
Liabilities from risk management activities (Note 7)
29,106 
70,315 
Customer advances
115,033 
114,480 
Coal mine reclamation
208,183 
207,453 
Deferred investment tax credit
152,114 
152,361 
Unrecognized tax benefits (Note 5)
13,502 
42,209 
Other
184,666 
185,659 
Total deferred credits and other
4,632,839 
4,753,117 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY (Note 8)
 
 
Common stock, no par value; authorized 150,000,000 shares, 110,389,065 and 110,280,703 issued at respective dates
2,497,485 
2,491,558 
Treasury stock at cost; 34,828 and 98,944 shares at respective dates
(844)
(4,308)
Total common stock
2,496,641 
2,487,250 
Retained earnings
1,801,047 
1,785,273 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(54,538)
(54,995)
Derivative instruments
(20,364)
(23,058)
Total accumulated other comprehensive loss
(74,902)
(78,053)
Total shareholders' equity
4,222,786 
4,194,470 
Noncontrolling interests (Note 6)
154,915 
145,990 
Total equity
4,377,701 
4,340,460 
TOTAL LIABILITIES AND EQUITY
$ 13,450,797 
$ 13,508,686 
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
Mar. 31, 2014
Dec. 31, 2013
EQUITY (Note 8)
 
 
Common stock, par value (in dollars per share)
   
   
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
110,389,065 
110,280,703 
Treasury stock at cost, shares
34,828 
98,944 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 24,691 
$ 32,836 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
122,394 
124,344 
Deferred fuel and purchased power
31,630 
31,194 
Deferred fuel and purchased power amortization
8,022 
1,122 
Allowance for equity funds used during construction
(7,442)
(6,864)
Deferred income taxes
8,810 
(9,265)
Deferred investment tax credit
(247)
21,428 
Change in derivative instruments fair value
(13)
333 
Changes in current assets and liabilities:
 
 
Customer and other receivables
25,986 
3,931 
Accrued unbilled revenues
7,889 
4,698 
Materials, supplies and fossil fuel
(187)
(9,386)
Income tax receivable
130,870 
(433)
Other current assets
(10,669)
(2,525)
Accounts payable
(50,990)
11,925 
Accrued taxes
48,139 
39,615 
Other current liabilities
(15,864)
(62,636)
Change in margin and collateral accounts - assets
(290)
933 
Change in margin and collateral accounts - liabilities
(29,075)
24,205 
Change in other long-term assets
(9,636)
(31,202)
Change in other long-term liabilities
(34,861)
37,904 
Net cash flow provided by operating activities
249,157 
212,157 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(207,459)
(182,859)
Contributions in aid of construction
7,736 
14,912 
Allowance for borrowed funds used during construction
(3,770)
(3,990)
Proceeds from nuclear decommissioning trust sales
103,157 
135,240 
Investment in nuclear decommissioning trust
(107,470)
(139,553)
Other
(702)
(470)
Net cash flow used for investing activities
(208,508)
(176,720)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
250,000 
104,307 
Short-term borrowings and payments - net
(143,625)
(92,175)
Dividends paid on common stock
(62,520)
(58,067)
Common stock equity issuance
9,390 
9,441 
Other
(36)
Net cash flow provided by (used for) financing activities
53,246 
(36,530)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
93,895 
(1,093)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
9,526 
26,202 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$ 103,421 
$ 25,109 
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”).  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 have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC).  Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading.

 

The following table shows more detail of previously reported amounts for the changes in deferred investment tax credit and income tax receivable. Previously reported amounts were netted in the Statement of Cash Flows (dollars in thousands):

 

Statement of Cash Flows for the
Year Ended March 31, 2013

 

As previously
reported

 

Changes to conform to
current year
presentation

 

Amount reported after
changes to conform to
current year
presentation

 

Cash Flows from Operating Activities

 

 

 

 

 

 

 

Deferred income taxes

 

$

12,163

 

$

(21,428

)

$

(9,265

)

Deferred investment tax credit

 

 

21,428

 

21,428

 

Accrued taxes and income tax receivable

 

39,182

 

(39,182

)

 

Income tax receivable

 

 

(433

)

(433

)

Accrued taxes

 

 

39,615

 

39,615

 

 

Supplemental Cash Flow Information

 

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

 

 

 

Three Months Ended
March 31,

 

 

 

2014

 

2013

 

Cash paid (received) during the period for:

 

 

 

 

 

Income taxes, net of refunds

 

$

(131,078

)

$

425

 

Interest, net of amounts capitalized

 

49,147

 

49,038

 

Significant non-cash investing and financing activities:

 

 

 

 

 

Accrued capital expenditures

 

$

24,908

 

$

6,575

 

 

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

 

Pinnacle West’s $200 million credit facility matures in November 2016.  At March 31, 2014, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At March 31, 2014, Pinnacle West had commercial paper borrowings of $10 million, no outstanding borrowings under its credit facility and no letters of credit outstanding.

 

APS

 

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. 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.  On January 15, 2014, these series of bonds were canceled.

 

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of Southern California Edison’s (“SCE”) 48% ownership interest in each of Units 4 and 5 of the Four Corners Power Plant (“Four Corners”) and to replenish cash used in 2013 to re-acquire two series of tax-exempt indebtedness.

 

At March 31, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in November 2016 and a $500 million facility that matures in April 2018.  APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2014, APS had no commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.

 

On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013.

 

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.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 

 

 

As of
March 31, 2014

 

As of
December 31, 2013

 

 

 

Carrying
Amount

 

Fair Value

 

Carrying
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Pinnacle West

 

$

125

 

$

125

 

$

125

 

$

125

 

APS

 

3,461

 

3,794

 

3,212

 

3,454

 

Total

 

$

3,586

 

$

3,919

 

$

3,337

 

$

3,579

 

 

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 March 31, 2014, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.8 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.1 billion, assuming APS’s total capitalization remains the same.

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 by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “2012 Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.

 

Settlement Agreement

 

The 2012 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 2012 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 2012 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 2012 Settlement Agreement.

 

Other key provisions of the 2012 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 increases in property taxes 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 acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);

 

·                                          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 APS’s 2009 retail rate case settlement agreement (the “2009 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 2012 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 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.

 

Cost Recovery Mechanisms

 

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

 

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

 

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, 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.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits.  On April 4, 2014, ACC staff submitted a proposal outlining various options which could be used to determine compliance with the renewable energy rules.  APS filed comments on the proposal and is awaiting the ACC’s selection of a proposal and modification of the rules to implement such proposal.

 

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

 

On June 1, 2012, APS filed its 2013 DSM 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.

 

On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.

 

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

 

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2014 and 2013 (dollars in millions):

 

 

 

Three Months Ended
March 31,

 

 

 

2014

 

2013

 

Beginning balance

 

$

21

 

$

73

 

Deferred fuel and purchased power costs — current period

 

(32

)

(31

)

Amounts charged to customers

 

(8

)

(1

)

Ending balance

 

$

(19

)

$

41

 

 

The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh.  Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.

 

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters In July 2008, the United States Federal 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 2012 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

 

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

 

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.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2013.

 

Lost Fixed Cost Recovery 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 rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement 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 a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014.

 

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.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are being held in 2014.

 

Net Metering

 

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.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid.  The new policy will be in effect until the next APS rate case.

 

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers.  The ACC acknowledged that the new charge addresses only a portion of the cost shift.

 

Beginning in May 2014, the ACC will conduct a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.

 

Four Corners

 

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013.  If approved, these adjustments would result in an average bill impact to residential customers of approximately 2%.  This includes the deferral for future recovery of all non-fuel operating cost for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $47 million as of March 31, 2014.  A hearing on this matter is scheduled to begin August 4, 2014 and we anticipate a decision by the end of 2014.  APS cannot predict the outcome of this matter.

 

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group.  However, this alternative arrangement was not approved by FERC.  In late March 2014, APS and SCE filed requests for rehearing with FERC.  We are unable to predict the timing or outcome of these requests.  Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.

 

Regulatory Assets and Liabilities

 

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

 

 

 

Remaining
Amortization

 

March 31, 2014

 

December 31, 2013

 

 

 

Period

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Pension and other postretirement benefits

 

(a)

 

$

 

$

313

 

$

 

$

314

 

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

 

2043

 

4

 

104

 

4

 

105

 

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

 

2016

 

 

26

 

5

 

29

 

Transmission vegetation management

 

2016

 

9

 

12

 

9

 

14

 

Coal reclamation

 

2038

 

8

 

16

 

8

 

18

 

Palo Verde VIEs (Note 6)

 

2046

 

 

42

 

 

41

 

Deferred compensation

 

2036

 

 

36

 

 

34

 

Deferred fuel and purchased power (b) (c)

 

2015

 

 

 

21

 

 

Tax expense of Medicare subsidy

 

2023

 

2

 

15

 

2

 

15

 

Loss on reacquired debt

 

2034

 

1

 

18

 

1

 

17

 

Income taxes — investment tax credit basis adjustment

 

2043

 

1

 

39

 

1

 

39

 

Pension and other postretirement benefits deferral

 

2015

 

8

 

2

 

8

 

4

 

Four Corners cost deferral

 

2024

 

 

47

 

 

37

 

Lost fixed cost recovery (b)

 

2015

 

32

 

 

25

 

 

Transmission cost adjustor (b)

 

2016

 

6

 

2

 

8

 

2

 

Retired power plant costs

 

2020

 

3

 

17

 

3

 

18

 

Other

 

Various

 

2

 

31

 

2

 

25

 

Total regulatory assets (d)

 

 

 

$

76

 

$

720

 

$

97

 

$

712

 

 

(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.  See Note 4 for further discussion.

(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

 

March 31, 2014

 

December 31, 2013

 

 

 

Period

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Removal costs

 

(a)

 

$

28

 

$

298

 

$

28

 

$

303

 

Asset retirement obligations

 

(a)

 

 

253

 

 

266

 

Renewable energy standard (b)

 

2015

 

35

 

16

 

33

 

15

 

Income taxes — change in rates

 

2043

 

1

 

73

 

 

74

 

Spent nuclear fuel

 

2047

 

5

 

37

 

6

 

36

 

Deferred gains on utility property

 

2019

 

2

 

9

 

2

 

10

 

Income taxes — deferred investment tax credit

 

2043

 

3

 

79

 

3

 

79

 

Demand side management (b)

 

2015

 

34

 

 

27

 

 

Deferred fuel and purchased power (b) (c)

 

2015

 

19

 

 

 

 

Deferred fuel and purchased power — mark to market

 

2015

 

9

 

 

 

 

Other

 

Various

 

 

19

 

 

18

 

Total regulatory liabilities

 

 

 

$

136

 

$

784

 

$

99

 

$

801

 

 

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

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

(c)                                  Subject to carrying charge.

 

Retirement Plans and Other Benefits
Retirement Plans and Other Benefits

4.                                      Retirement Plans and Other Benefits

 

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

 

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We amortized approximately $2 million for the three months ended March 31, 2014 and 2013, 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 March 31,

 

Three Months
Ended March 31,

 

 

 

2014

 

2013

 

2014

 

2013

 

Service cost — benefits earned during the period

 

$

15

 

$

17

 

$

5

 

$

6

 

Interest cost on benefit obligation

 

32

 

29

 

11

 

10

 

Expected return on plan assets

 

(40

)

(37

)

(12

)

(11

)

Amortization of net actuarial loss

 

2

 

9

 

 

3

 

Net periodic benefit cost

 

$

9

 

$

18

 

$

4

 

$

8

 

Portion of cost charged to expense

 

$

5

 

$

10

 

$

3

 

$

5

 

 

Contributions

 

The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015, and $122 million in 2016).  Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $105 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016).  The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.

Income Taxes
Income Taxes

5.                                      Income Taxes

 

During the first quarter of 2014, a $135 million cash refund was received from the IRS related to tax returns for the years ended December 31, 2008 and 2009.  This refund was classified as a current income tax receivable at December 31, 2013.

 

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.

 

In January 2014, we prospectively adopted guidance requiring unrecognized tax benefits to be presented as a reduction to any available deferred income tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  As a result of this guidance, $29 million of unrecognized tax benefits were recorded as a reduction to net current deferred income tax assets on the Condensed Consolidated Balance Sheets and $16 million were recorded as an increase to net current deferred income tax liabilities on the APS Condensed Consolidated Balance Sheets as of March 31, 2014.

 

As of March 31, 2014, the tax year ended December 31, 2010 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 2010.

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 during 2014 and 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 determined through an appraisal process.  During 2014, APS must notify the lessor trust which of these two options (lease renewal or purchasing the assets) it will exercise.

 

As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three months ended March 31, 2014 of $9 million and for the three months ended March 31, 2013 of $8 million, entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders remains the same.  Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

 

Our Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):

 

 

 

March 31,
2014

 

December 31,
2013

 

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

 

$

124

 

$

125

 

Current maturities of long-term debt

 

26

 

26

 

Long-term debt excluding current maturities

 

13

 

13

 

Equity — Noncontrolling interests

 

155

 

146

 

 

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 leases.

 

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of March 31, 2014, APS would have been required to pay the noncontrolling equity participants approximately $133 million and assume $39 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 cash flow 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 OCI, but are deferred through the PSA.  The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, 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.  When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA.  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 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.

 

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses 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 March 31, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

 

Commodity

 

Quantity

 

Power

 

5,503

 

GWh

 

Gas

 

107

 

Billion cubic feet

 

 

Gains and Losses from Derivative Instruments

 

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, 2014 and 2013 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
March 31,

 

Commodity Contracts

 

Location

 

2014

 

2013

 

 

 

 

 

 

 

 

 

Gain Recognized in OCI on Derivative Instruments (Effective Portion)

 

OCI — derivative instruments

 

$

177

 

$

96

 

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)

 

Fuel and purchased power (b)

 

(4,439

)

(8,353

)

 

(a)                                 During the three months ended March 31, 2014 and 2013, we had no amounts reclassified from accumulated OCI 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 $19 million before income taxes will be reclassified from accumulated OCI 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 months ended March 31, 2014 and 2013 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
March 31,

 

Commodity Contracts

 

Location

 

2014

 

2013

 

 

 

 

 

 

 

 

 

Net Loss Recognized in Income

 

Operating revenues (a)

 

$

(92

)

$

(117

)

 

 

 

 

 

 

 

 

Net Gain Recognized in Income

 

Fuel and purchased power (a)

 

18,107

 

17,350

 

Total

 

 

 

$

18,015

 

$

17,233

 

 

(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 a 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 March 31, 2014 and December 31, 2013, include gross liabilities of $4 million and $5 million, respectively, 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 March 31, 2014 and December 31, 2013.  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 March 31, 2014:
(dollars in thousands)

 

Gross
Recognized
Derivatives
(a)

 

Amounts
Offset
 (b)

 

Net
Recognized
Derivatives

 

Other
(c)

 

Amount
Reported on
Balance Sheet

 

Current Assets

 

$

32,470

 

$

(15,816

)

$

16,654

 

$

297

 

$

16,951

 

Investments and Other Assets

 

23,913

 

(2,287

)

21,626

 

 

21,626

 

Total Assets

 

56,383

 

(18,103

)

38,280

 

297

 

38,577

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(42,161

)

30,897

 

(11,264

)

(8,643

)

(19,907

)

Deferred Credits and Other

 

(65,511

)

36,405

 

(29,106

)

 

(29,106

)

Total Liabilities

 

(107,672

)

67,302

 

(40,370

)

(8,643

)

(49,013

)

Total

 

$

(51,289

)

$

49,199

 

$

(2,090

)

$

(8,346

)

$

(10,436

)

 

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

(b)         Includes cash collateral provided to counterparties of $49,199.

(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 $8,643, and cash margin provided to counterparties of $297.

 

As of December 31, 2013:
(dollars in thousands)

 

Gross
Recognized
Derivatives

(a)

 

Amounts
Offset
(b)

 

Net
Recognized
Derivatives

 

Other
(c)

 

Amount
Reported on
Balance Sheet

 

Current Assets

 

$

24,587

 

$

(7,425

)

$

17,162

 

$

7

 

$

17,169

 

Investments and Other Assets

 

25,364

 

(1,549

)

23,815

 

 

23,815

 

Total Assets

 

49,951

 

(8,974

)

40,977

 

7

 

40,984

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(50,540

)

26,166

 

(24,374

)

(7,518

)

(31,892

)

Deferred Credits and Other

 

(72,123

)

1,808

 

(70,315

)

 

(70,315

)

Total Liabilities

 

(122,663

)

27,974

 

(94,689

)

(7,518

)

(102,207

)

Total

 

$

(72,712

)

$

19,000

 

$

(53,712

)

$

(7,511

)

$

(61,223

)

 

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

(b)         Includes cash collateral provided to counterparties of $19,000.

(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 $7,518, and cash margin provided to counterparties of $7.

 

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 84% of Pinnacle West’s $39 million of risk management assets as of March 31, 2014.  This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

 

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

 

The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, 2014 (dollars in millions):

 

 

 

March 31,
2014

 

Aggregate Fair Value of Derivative Instruments in a Net Liability Position

 

$

108

 

Cash Collateral Posted

 

49

 

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

 

50

 

 

(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 $180 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 months ended March 31, 2014 and 2013 (dollars in thousands):

 

 

 

Three Months Ended March 31, 2014

 

Three Months Ended March 31, 2013

 

 

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, January 1

 

$

4,194,470

 

$

145,990

 

$

4,340,460

 

$

3,972,806

 

$

129,483

 

$

4,102,289

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

15,766

 

8,925

 

24,691

 

24,444

 

8,392

 

32,836

 

Other comprehensive income

 

3,151

 

 

3,151

 

6,077

 

 

6,077

 

Total comprehensive income

 

18,917

 

8,925

 

27,842

 

30,521

 

8,392

 

38,913

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

2,592

 

 

2,592

 

2,574

 

 

2,574

 

Reissuance (purchase) of treasury stock — net

 

3,465

 

 

3,465

 

(6,271

)

 

(6,271

)

Other (primarily stock compensation)

 

3,342

 

 

3,342

 

14,825

 

 

14,825

 

Ending balance, March 31

 

$

4,222,786

 

$

154,915

 

$

4,377,701

 

$

4,014,455

 

$

137,875

 

$

4,152,330

 

 

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 (“Court of Federal Claims”).  The lawsuit seeks to recover 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 Protection Act.  This lawsuit is currently pending in the Court of Federal Claims.

 

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 retrospective premium 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 million, with an annual payment limitation of approximately $16.5 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 replacement 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, 2014, a sublimit of $2.25 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 $20 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 $54 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

 

There have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2013 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.

 

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.

 

On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS.  FERC Staff alleges that each of the named entities violated varying numbers of NERC Reliability Standards.  APS is alleged to have violated seven Reliability Standard Requirements.  The allegations of violations are preliminary determinations by FERC Staff and do not constitute findings by FERC itself that any violations have occurred.

 

APS intends to work with FERC Staff to resolve the matter.  If violations of the 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.  APS cannot predict the timing or financial or operational impacts that may result from the Staff’s Notice of Alleged Violations, including any payments that may result from a settlement if one is reached, or any claims that may be made as a result of the outages.

 

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 filed a motion to dismiss, which the court granted on December 9, 2013.  On January 13, 2014, the plaintiffs appealed the lower court’s decision.  The appeal is now pending before the Ninth Circuit Court of Appeals.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

 

Clean Air Act Citizen 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 environmental 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 (“CCRs”).  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 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $350 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 $130 million for Cholla Units 2 and 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, Clean Water 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.  Briefing in the case was completed in February 2014, and the parties are waiting for the court to schedule oral argument.

 

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.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed 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 March 31, 2014, 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 $24 million at March 31, 2014.  Additionally, APS has issued a letter of credit to support collateral obligations under a natural gas tolling contract entered into with third parties.  At March 31, 2014, that letter of credit totaled $5 million and will expire in 2014.

 

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 March 31, 2014.

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 months ended March 31, 2014 and 2013 (dollars in thousands):

 

 

 

Three Months Ended
March 31,

 

 

 

2014

 

2013

 

Other income:

 

 

 

 

 

Interest income

 

$

251

 

$

76

 

Miscellaneous

 

2,116

 

682

 

Total other income

 

$

2,367

 

$

758

 

 

 

 

 

 

 

Other expense:

 

 

 

 

 

Non-operating costs

 

$

(2,372

)

$

(1,932

)

Investment losses — net

 

(140

)

(112

)

Miscellaneous

 

(2,172

)

(1,708

)

Total other expense

 

$

(4,684

)

$

(3,752

)

 

Earnings Per Share
Earnings Per Share

11.          Earnings Per Share

 

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):

 

 

 

Three Months Ended
March 31,

 

 

 

2014

 

2013

 

 

 

 

 

 

 

Net income attributable to common shareholders

 

$

15,766

 

$

24,444

 

Average common shares outstanding — basic

 

110,257

 

109,832

 

Net effect of dilutive securities:

 

 

 

 

 

Contingently issuable performance shares and restricted stock units

 

631

 

1,003

 

Average common shares outstanding — diluted

 

110,888

 

110,835

 

Earnings per average common share attributable to common shareholders — basic

 

$

0.14

 

$

0.22

 

Earnings per average common share attributable to common shareholders — diluted

 

$

0.14

 

$

0.22

 

 

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 U.S. Treasury securities.

 

Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves).  This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities.  This category also includes investments in common and collective trusts and commingled funds that are redeemable and valued based on 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 2013 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 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 the 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 Trusts

 

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 U.S. government fixed income securities.  We may transact in this commingled fund on a daily basis at the NAV.

 

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield 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.

 

We price securities using information provided by our trustee for our nuclear decommissioning trust assets.  Our trustee uses 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 March 31, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

 

 

 

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

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs (a)
(Level 3)

 

Other

 

Balance at
March 31,
2014

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Risk management activities — derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

 

$

21

 

$

36

 

$

(18)

(b)

$

39

 

Nuclear decommissioning trust:

 

 

 

 

 

 

 

 

 

 

 

U.S. commingled equity funds

 

 

277

 

 

 

277

 

Fixed income securities:

 

 

 

 

 

 

 

 

 

 

 

U.S. Treasury

 

120

 

 

 

 

120

 

Cash and cash equivalent funds

 

 

14

 

 

(5)

(c)

9

 

Corporate debt

 

 

96

 

 

 

96

 

Mortgage-backed securities

 

 

79

 

 

 

79

 

Municipality bonds

 

 

64

 

 

 

64

 

Other

 

 

13

 

 

 

13

 

Subtotal nuclear decommissioning trust

 

120

 

543

 

 

(5

)

658

 

Total

 

$

120

 

$

564

 

$

36

 

$

(23

)

$

697

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

Risk management activities — derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

 

$

(23

)

$

(85

)

$

59

(b)

$

(49

)

 

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

(b)                                 Primarily represents counterparty netting, margin and collateral (see Note 7).

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

 

The following table presents the fair value at December 31, 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
December 31,
2013

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Risk management activities — derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity Contracts

 

$

 

$

9

 

$

41

 

$

(9)

 (b)

$

41

 

Nuclear decommissioning trust:

 

 

 

 

 

 

 

 

 

 

 

U.S. commingled equity funds

 

 

272

 

 

 

272

 

Fixed income securities:

 

 

 

 

 

 

 

 

 

 

 

U.S. Treasury

 

107

 

 

 

 

107

 

Cash and cash equivalent funds

 

 

11

 

 

(3)

 (c)

8

 

Corporate debt

 

 

88

 

 

 

88

 

Mortgage-backed securities

 

 

85

 

 

 

85

 

Municipality bonds

 

 

71

 

 

 

71

 

Other

 

 

11

 

 

 

11

 

Subtotal nuclear decommissioning trust

 

107

 

538

 

 

(3

)

642

 

Total

 

$

107

 

$

547

 

$

41

 

$

(12

)

$

683

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

Risk management activities — derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

 

$

(33

)

$

(90

)

$

21

(b)

$

(102

)

 

 

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

(b)                                 Represents counterparty netting, margin and collateral (see Note 7).

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

 

Fair Value Measurements Classified as Level 3

 

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote and option model inputs.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).

 

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

 

Our option contracts classified as Level 3 primarily relate to purchase heat rate options.  The significant unobservable inputs for these instruments include electricity prices, gas prices and volatilities.  If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease.  If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase.  The commodity prices and volatilities do not always move in corresponding directions.  The options’ fair values are impacted by the net changes of these various inputs.

 

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

 

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at March 31, 2014 and December 31, 2013:

 

 

 

March 31, 2014
Fair Value (millions)

 

Valuation

 

Significant

 

 

 

Weighted-

 

Commodity Contracts

 

Assets

 

Liabilities

 

Technique

 

Unobservable Input

 

Range

 

Average

 

Electricity:

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward Contracts (a)

 

$

34

 

$

60

 

Discounted cash flows

 

Electricity forward price (per MWh)

 

$23.13 — $67.47

 

$

42.28

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Option Contracts (b)

 

 

22

 

Option model

 

Electricity forward price (per MWh)

 

$40.32 — $93.94

 

$

60.49

 

 

 

 

 

 

 

 

 

Natural gas forward price (per MMbtu)

 

$3.64 — $3.84

 

$

3.76

 

 

 

 

 

 

 

 

 

Electricity price volatilities

 

24% — 100%

 

52

%

 

 

 

 

 

 

 

 

Natural gas price volatilities

 

23% — 44%

 

30

%

Natural Gas:

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward Contracts (a)

 

2

 

3

 

Discounted cash flows

 

Natural gas forward price (per MMbtu)

 

$3.60 — $4.40

 

$

3.91

 

Total

 

$

36

 

$

85

 

 

 

 

 

 

 

 

 

 

(a)                                 Includes swaps and physical and financial contracts.

(b)                                 Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.

 

 

 

December 31, 2013
Fair Value (millions)

 

 

 

 

 

 

 

 

 

Commodity Contracts

 

Assets

 

Liabilities

 

Valuation
Technique

 

Significant
Unobservable Input

 

Range

 

Weighted-
Average

 

Electricity:

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward Contracts (a)

 

$

40

 

$

66

 

Discounted cash flows

 

Electricity forward price (per MWh)

 

$24.89 - $65.04

 

$

41.09

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Option Contracts (b)

 

 

19

 

Option model

 

Electricity forward price (per MWh)

 

$39.91 - $85.41

 

$

58.70

 

 

 

 

 

 

 

 

 

Natural gas forward price (per MMbtu)

 

$3.57 - $3.80

 

$

3.71

 

 

 

 

 

 

 

 

 

Electricity price volatilities

 

35% - 94%

 

59

%

 

 

 

 

 

 

 

 

Natural gas price volatilities

 

22% - 36%

 

27

%

Natural Gas:

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward Contracts (a)

 

1

 

5

 

Discounted cash flows

 

Natural gas forward price (per MMbtu)

 

$3.47 - $4.31

 

$

3.87

 

Total

 

$

41

 

$

90

 

 

 

 

 

 

 

 

 

 

(a)                                 Includes swaps and physical and financial contracts.

(b)                                 Electricity and gas price volatilities are based on historical forward price movements due to lack of market quotes for implied volatilities.

 

The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2014 and 2013 (dollars in millions):

 

Commodity Contracts

 

Three Months Ended
March 31,

 

 

 

2014

 

2013

 

Net derivative balance at beginning of period

 

$

(49

)

$

(48

)

Total net gains (losses) realized/unrealized:

 

 

 

 

 

Deferred as a regulatory asset or liability

 

4

 

(1

)

Settlements

 

 

(2

)

Transfers into Level 3 from Level 2

 

(3

)

(1

)

Transfers from Level 3 into Level 2

 

(1

)

(1

)

Net derivative balance at end of period

 

$

(49

)

$

(53

)

 

 

 

 

 

 

Net unrealized gains included in earnings related to instruments still held at end of period

 

$

 

$

 

 

Amounts included in earnings are either recorded in operating revenues or purchased power depending on the nature of the underlying contract.

 

Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period.  We had no significant Level 1 transfers to or from any other hierarchy level.  Transfers in or out of Level 3 are typically related to our heat rate options and long-dated energy transactions that extend beyond available quoted periods.

 

Financial Instruments Not Carried at Fair Value

 

The carrying value of our net accounts receivable, accounts payable and any short-term borrowings approximate fair value.  Our short-term borrowings are classified within Level 2 of the fair value hierarchy.  For our long-term debt fair values, see Note 2.

Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts

13.                               Nuclear Decommissioning Trusts

 

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities.  APS classifies investments in decommissioning trust funds as available for sale.  As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets.  See Note 12 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy.  Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at March 31, 2014 and December 31, 2013 (dollars in millions):

 

 

 

Fair Value

 

Total
Unrealized
Gains

 

Total
Unrealized
Losses

 

March 31, 2014

 

 

 

 

 

 

 

Equity securities

 

$

277

 

$

132

 

$

 

Fixed income securities

 

386

 

13

 

(3

)

Net payables (a)

 

(5

)

 

 

Total

 

$

658

 

$

145

 

$

(3

)

 

(a)                                 Net payables relate to pending securities sales and purchases.

 

 

 

Fair Value

 

Total
Unrealized
Gains

 

Total
Unrealized
Losses

 

December 31, 2013

 

 

 

 

 

 

 

Equity securities

 

$

272

 

$

129

 

$

 

Fixed income securities

 

373

 

11

 

(6

)

Net payables (a)

 

(3

)

 

 

Total

 

$

642

 

$

140

 

$

(6

)

 

(a)                                 Net payables relate to pending securities sales and purchases.

 

The costs of securities sold are determined on the basis of specific identification.  The following table sets forth approximate realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

 

 

 

Three Months Ended
March 31,

 

 

 

2014