10-Q 1 a06301510-q.htm 10-Q 06.30.15 10-Q



 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
 

FORM 10-Q
 
(Mark One)
 
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2015
 
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to          
 
Commission File
Number
 
Exact Name of Each Registrant as specified in its
charter; State of Incorporation; Address; and
Telephone Number
 
IRS Employer
Identification No.
1-8962
 
PINNACLE WEST CAPITAL CORPORATION
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona  85072-3999
(602) 250-1000
 
86-0512431
1-4473
 
ARIZONA PUBLIC SERVICE COMPANY
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona  85072-3999
(602) 250-1000
 
86-0011170
 
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
PINNACLE WEST CAPITAL CORPORATION
Yes  x   No o
ARIZONA PUBLIC SERVICE COMPANY
Yes  x   No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
 
PINNACLE WEST CAPITAL CORPORATION
Yes  x   No o
ARIZONA PUBLIC SERVICE COMPANY
Yes  x   No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
 
PINNACLE WEST CAPITAL CORPORATION
 
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
 
ARIZONA PUBLIC SERVICE COMPANY
 
Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o
 
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
PINNACLE WEST CAPITAL CORPORATION
Yes  o   No x
ARIZONA PUBLIC SERVICE COMPANY
Yes  o   No x
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
 
PINNACLE WEST CAPITAL CORPORATION
Number of shares of common stock, no par value, outstanding as of July 24, 2015: 110,813,659
ARIZONA PUBLIC SERVICE COMPANY
Number of shares of common stock, $2.50 par value, outstanding as of July 24, 2015: 71,264,947
 
Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.






TABLE OF CONTENTS
 
This combined Form 10-Q is separately provided by Pinnacle West Capital Corporation ("Pinnacle West") and Arizona Public Service Company ("APS").  Any use of the words "Company," "we," and "our" refer to Pinnacle West.  Each registrant is providing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries.  Except as stated in the preceding sentence, neither registrant is providing any information that does not relate to such registrant, and therefore makes no representation as to any such information.  The information required with respect to each company is set forth within the applicable items.  Item 1 of this report includes Condensed Consolidated Financial Statements of Pinnacle West and Condensed Consolidated Financial Statements of APS.  Item 1 also includes Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS, and Supplemental Notes, which only relate to APS’s Condensed Consolidated Financial Statements.


1



FORWARD-LOOKING STATEMENTS
 
This document contains forward-looking statements based on current expectations.  These forward-looking statements are often identified by words such as "estimate," "predict," "may," "believe," "plan," "expect," "require," "intend," "assume" and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2014 ("2014 Form 10-K") and in Part I, Item 2 — "Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this report, these factors include, but are not limited to:
 
our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;
variations in demand for electricity, including those due to weather, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation;
power plant and transmission system performance and outages;
competition in retail and wholesale power markets;
regulatory and judicial decisions, developments and proceedings;
new legislation or regulation, including those relating to environmental requirements, nuclear plant operations and potential deregulation of retail electric markets;
fuel and water supply availability;
our ability to achieve timely and adequate rate recovery of our costs, including returns on debt and equity capital;
our ability to meet renewable energy and energy efficiency mandates and recover related costs;
risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;
current and future economic conditions in Arizona, particularly in real estate markets;
the development of new technologies which may affect electric sales or delivery;
the cost of debt and equity capital and the ability to access capital markets when required;
environmental and other concerns surrounding coal-fired generation;
volatile fuel and purchased power costs;
the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;
the liquidity of wholesale power markets and the use of derivative contracts in our business;
potential shortfalls in insurance coverage;
new accounting requirements or new interpretations of existing requirements;
generation, transmission and distribution facility and system conditions and operating costs;
 the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our region;
the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations; and
 restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission ("ACC") orders.
 
These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our 2014 Form 10-K, which readers should review carefully before placing any reliance on our financial statements or disclosures.  Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.


2



PART I — FINANCIAL INFORMATION
 
ITEM 1.  FINANCIAL STATEMENTS
 
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)
 
 
Three Months Ended 
 June 30,
 
2015
 
2014
 
 
 
 
OPERATING REVENUES
$
890,648

 
$
906,264

 
 
 
 
OPERATING EXPENSES
 

 
 

Fuel and purchased power
281,477

 
290,854

Operations and maintenance
210,965

 
211,222

Depreciation and amortization
122,739

 
105,150

Taxes other than income taxes
43,032

 
44,004

Other expenses
462

 
921

Total
658,675

 
652,151

OPERATING INCOME
231,973

 
254,113

OTHER INCOME (DEDUCTIONS)
 

 
 

Allowance for equity funds used during construction
9,345

 
7,499

Other income (Note 9)
175

 
2,781

Other expense (Note 9)
(2,609
)
 
(508
)
Total
6,911

 
9,772

INTEREST EXPENSE
 

 
 

Interest charges
48,328

 
51,751

Allowance for borrowed funds used during construction
(4,322
)
 
(3,790
)
Total
44,006

 
47,961

INCOME BEFORE INCOME TAXES
194,878

 
215,924

INCOME TAXES
67,371

 
74,540

NET INCOME
127,507

 
141,384

Less: Net income attributable to noncontrolling interests (Note 6)
4,605

 
8,926

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$
122,902

 
$
132,458

 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC
110,986

 
110,565

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED
111,460

 
111,002

 
 
 
 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 

 
 

Net income attributable to common shareholders — basic
$
1.11

 
$
1.20

Net income attributable to common shareholders — diluted
$
1.10

 
$
1.19

 
 
 
 
DIVIDENDS DECLARED PER SHARE
$
1.19

 
$
1.14

 
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

3



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(dollars in thousands)
 
 
Three Months Ended 
 June 30,
 
2015
 
2014
 
 
 
 
NET INCOME
$
127,507

 
$
141,384

 
 
 
 
OTHER COMPREHENSIVE INCOME, NET OF TAX
 

 
 

Derivative instruments:
 

 
 

Net unrealized gain, net of tax expense of $16 and $26
25

 
40

Reclassification of net realized loss, net of tax benefit of $556 and $1,261
874

 
1,955

Pension and other postretirement benefits activity, net of tax benefit of $74 and $845
(117
)
 
(1,310
)
Total other comprehensive income
782

 
685

 
 
 
 
COMPREHENSIVE INCOME
128,289

 
142,069

Less: Comprehensive income attributable to noncontrolling interests
4,605

 
8,926

 
 
 
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$
123,684

 
$
133,143

 
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

4



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)
 
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
 
 
 
OPERATING REVENUES
$
1,561,867

 
$
1,592,515

 
 
 
 
OPERATING EXPENSES
 

 
 

Fuel and purchased power
504,714

 
540,640

Operations and maintenance
425,909

 
424,104

Depreciation and amortization
243,688

 
206,922

Taxes other than income taxes
86,248

 
89,849

Other expenses
1,651

 
1,717

Total
1,262,210

 
1,263,232

OPERATING INCOME
299,657

 
329,283

OTHER INCOME (DEDUCTIONS)
 

 
 

Allowance for equity funds used during construction
18,569

 
14,941

Other income (Note 9)
410

 
5,148

Other expense (Note 9)
(6,895
)
 
(5,192
)
Total
12,084

 
14,897

INTEREST EXPENSE
 

 
 

Interest charges
96,727

 
104,720

Allowance for borrowed funds used during construction
(8,538
)
 
(7,560
)
Total
88,189

 
97,160

INCOME BEFORE INCOME TAXES
223,552

 
247,020

INCOME TAXES
75,318

 
80,945

NET INCOME
148,234

 
166,075

Less: Net income attributable to noncontrolling interests (Note 6)
9,210

 
17,851

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$
139,024

 
$
148,224

 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC
110,958

 
110,546

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED
111,426

 
110,925

 
 
 
 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 

 
 

Net income attributable to common shareholders — basic
$
1.25

 
$
1.34

Net income attributable to common shareholders — diluted
$
1.25

 
$
1.34

 
 
 
 
DIVIDENDS DECLARED PER SHARE
$
1.19

 
$
1.14

 
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

5



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(dollars in thousands)
 
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
 
 
 
NET INCOME
$
148,234

 
$
166,075

 
 
 
 
OTHER COMPREHENSIVE INCOME, NET OF TAX
 

 
 

Derivative instruments:
 

 
 

Net unrealized loss, net of tax expense of $489 and $624
(775
)
 
(381
)
Reclassification of net realized loss, net of tax benefit of $923 and $2,584
2,850

 
5,070

Pension and other postretirement benefits activity, net of tax benefit (expense) of $(793) and $128
466

 
(853
)
Total other comprehensive income
2,541

 
3,836

 
 
 
 
COMPREHENSIVE INCOME
150,775

 
169,911

Less: Comprehensive income attributable to noncontrolling interests
9,210

 
17,851

 
 
 
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$
141,565

 
$
152,060

 
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

6



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 
 
June 30, 2015
 
December 31, 2014
ASSETS
 

 
 

 
 
 
 
CURRENT ASSETS
 

 
 

Cash and cash equivalents
$
13,557

 
$
7,604

Customer and other receivables
289,236

 
297,740

Accrued unbilled revenues
185,216

 
100,533

Allowance for doubtful accounts
(2,518
)
 
(3,094
)
Materials and supplies (at average cost)
231,101

 
218,889

Fossil fuel (at average cost)
43,196

 
37,097

Deferred income taxes
77,841

 
122,232

Income tax receivable (Note 5)

 
3,098

Assets from risk management activities (Note 7)
14,722

 
13,785

Deferred fuel and purchased power regulatory asset (Note 3)

 
6,926

Other regulatory assets (Note 3)
134,578

 
129,808

Other current assets
44,827

 
38,817

Total current assets
1,031,756

 
973,435

INVESTMENTS AND OTHER ASSETS
 

 
 

Assets from risk management activities (Note 7)
18,513

 
17,620

Nuclear decommissioning trust (Note 12)
723,582

 
713,866

Other assets
51,987

 
54,047

Total investments and other assets
794,082

 
785,533

PROPERTY, PLANT AND EQUIPMENT
 

 
 

Plant in service and held for future use
15,926,594

 
15,543,063

Accumulated depreciation and amortization
(5,497,350
)
 
(5,397,751
)
Net
10,429,244

 
10,145,312

Construction work in progress
638,285

 
682,807

Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
119,320

 
121,255

Intangible assets, net of accumulated amortization
127,742

 
119,755

Nuclear fuel, net of accumulated amortization
156,608

 
125,201

Total property, plant and equipment
11,471,199

 
11,194,330

DEFERRED DEBITS
 

 
 

Regulatory assets (Note 3)
1,081,113

 
1,054,087

Assets for other postretirement benefits (Note 4)
168,755

 
152,290

Other
154,578

 
153,857

Total deferred debits
1,404,446

 
1,360,234

 
 
 
 
TOTAL ASSETS
$
14,701,483

 
$
14,313,532

 
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

7



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 
June 30, 2015
 
December 31, 2014
LIABILITIES AND EQUITY
 

 
 

 
 
 
 
CURRENT LIABILITIES
 

 
 

Accounts payable
$
326,119

 
$
295,211

Accrued taxes (Note 5)
155,812

 
140,613

Accrued interest
54,547

 
52,603

Common dividends payable
65,933

 
65,790

Short-term borrowings (Note 2)
157,500

 
147,400

Current maturities of long-term debt (Note 2)
102,723

 
383,570

Customer deposits
72,785

 
72,307

Liabilities from risk management activities (Note 7)
60,673

 
59,676

Deferred fuel and purchased power regulatory liability (Note 3)
16,209

 

Liabilities for asset retirements (Note 15)
28,543

 
32,462

Other regulatory liabilities (Note 3)
136,273

 
130,549

Other current liabilities
162,742

 
178,962

Total current liabilities
1,339,859

 
1,559,143

LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
3,565,857

 
3,031,215

DEFERRED CREDITS AND OTHER
 

 
 

Deferred income taxes
2,614,274

 
2,582,636

Regulatory liabilities (Note 3)
1,016,991

 
1,051,196

Liabilities for asset retirements (Note 15)
419,072

 
358,288

Liabilities for pension benefits (Note 4)
425,002

 
453,736

Liabilities from risk management activities (Note 7)
87,689

 
50,602

Customer advances
120,063

 
123,052

Coal mine reclamation
200,155

 
198,292

Deferred investment tax credit
176,389

 
178,607

Unrecognized tax benefits (Note 5)
14,311

 
19,377

Other
196,178

 
188,286

Total deferred credits and other
5,270,124

 
5,204,072

COMMITMENTS AND CONTINGENCIES (SEE NOTES)


 


EQUITY
 

 
 

Common stock, no par value; authorized 150,000,000 shares, 110,865,030 and 110,649,762 issued at respective dates
2,526,945

 
2,512,970

Treasury stock at cost; 53,559 and 78,400 shares at respective dates
(1,765
)
 
(3,401
)
Total common stock
2,525,180

 
2,509,569

Retained earnings
1,933,256

 
1,926,065

Accumulated other comprehensive loss:
 

 
 

Pension and other postretirement benefits
(57,290
)
 
(57,756
)
Derivative instruments
(8,310
)
 
(10,385
)
Total accumulated other comprehensive loss
(65,600
)
 
(68,141
)
Total shareholders’ equity
4,392,836

 
4,367,493

Noncontrolling interests (Note 6)
132,807

 
151,609

Total equity
4,525,643

 
4,519,102

 
 
 
 
TOTAL LIABILITIES AND EQUITY
$
14,701,483

 
$
14,313,532

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

8



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
 
 
Six Months Ended 
 June 30,
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 

 
 

Net income
$
148,234

 
$
166,075

Adjustments to reconcile net income to net cash provided by operating activities:
 

 
 

Depreciation and amortization including nuclear fuel
282,218

 
246,371

Deferred fuel and purchased power
11,711

 
1,315

Deferred fuel and purchased power amortization
11,424

 
18,399

Allowance for equity funds used during construction
(18,569
)
 
(14,941
)
Deferred income taxes
65,377

 
32,611

Deferred investment tax credit
(2,218
)
 
28,875

Change in derivative instruments fair value
(225
)
 
49

Changes in current assets and liabilities:
 

 
 

Customer and other receivables
(17,402
)
 
(64,986
)
Accrued unbilled revenues
(84,683
)
 
(75,648
)
Materials, supplies and fossil fuel
(18,311
)
 
(9,435
)
Income tax receivable
3,098

 
135,517

Other current assets
(8,728
)
 
(14,038
)
Accounts payable
36,634

 
30,725

Accrued taxes
15,199

 
30,709

Other current liabilities
(13,138
)
 
19,978

Change in margin and collateral accounts — assets
(4,552
)
 
(2,107
)
Change in margin and collateral accounts — liabilities
26,853

 
(22,425
)
Change in other long-term assets
(4,817
)
 
(19,243
)
Change in other long-term liabilities
(33,811
)
 
(22,735
)
Net cash flow provided by operating activities
394,294

 
465,066

CASH FLOWS FROM INVESTING ACTIVITIES
 

 
 

Capital expenditures
(531,035
)
 
(388,752
)
Contributions in aid of construction
41,010

 
12,646

Allowance for borrowed funds used during construction
(8,538
)
 
(7,560
)
Proceeds from nuclear decommissioning trust sales
225,779

 
199,224

Investment in nuclear decommissioning trust
(234,651
)
 
(207,848
)
Other
(2,068
)
 
(678
)
Net cash flow used for investing activities
(509,503
)
 
(392,968
)
CASH FLOWS FROM FINANCING ACTIVITIES
 

 
 

Issuance of long-term debt
600,000

 
535,975

Repayment of long-term debt
(344,847
)
 
(503,583
)
Short-term borrowings and payments — net
10,100

 
23,525

Dividends paid on common stock
(128,241
)
 
(125,138
)
Common stock equity issuance
12,161

 
12,625

Distributions to noncontrolling interest
(28,012
)
 
(15,869
)
Other
1

 
2

Net cash flow provided by (used for) financing activities
121,162

 
(72,463
)
 
 
 
 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
5,953

 
(365
)
 
 
 
 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
7,604

 
9,526

 
 
 
 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
13,557

 
$
9,161

 
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

9



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(dollars in thousands, except per share amounts)
 
Common Stock
 
Treasury Stock
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Noncontrolling Interests
 
Total
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
 
 
 
 
Balance, January 1, 2014
110,280,703

 
$
2,491,558

 
(98,944
)
 
$
(4,308
)
 
$
1,785,273

 
$
(78,053
)
 
$
145,990

 
$
4,340,460

Net income
 
 
 
 
 
 
 
 
148,224

 
 
 
17,851

 
166,075

Other comprehensive income
 
 
 
 
 
 
 
 
 
 
3,836

 
 
 
3,836

Dividends on common stock
 
 
 
 
 
 
 
 
(125,265
)
 
 
 
 
 
(125,265
)
Issuance of common stock
149,753

 
8,506

 
 
 
 
 
 
 
 
 
 
 
8,506

Purchase of treasury stock (a)
 
 
 
 
(82,474
)
 
(4,535
)
 
 
 
 
 
 
 
(4,535
)
Stock-based compensation and other
 
 
 
 
157,594

 
8,654

 

 
 
 
 
 
8,654

Net capital activities by noncontrolling interests
 
 
 
 
 
 
 
 
 
 
 
 
(15,869
)
 
(15,869
)
Balance, June 30, 2014
110,430,456

 
$
2,500,064

 
(23,824
)
 
$
(189
)
 
$
1,808,232

 
$
(74,217
)
 
$
147,972

 
$
4,381,862

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, January 1, 2015
110,649,762

 
$
2,512,970

 
(78,400
)
 
$
(3,401
)
 
$
1,926,065

 
$
(68,141
)
 
$
151,609

 
$
4,519,102

Net income
 
 
 
 
 
 
 
 
139,024

 
 
 
9,210

 
148,234

Other comprehensive income
 
 
 
 
 
 
 
 
 
 
2,541

 
 
 
2,541

Dividends on common stock
 
 
 
 
 
 
 
 
(131,833
)
 
 
 
 
 
(131,833
)
Issuance of common stock
215,268

 
13,975

 
 
 
 
 
 
 
 
 
 
 
13,975

Purchase of treasury stock (a)
 
 
 
 
(93,280
)
 
(6,096
)
 
 
 
 
 
 
 
(6,096
)
Stock-based compensation and other
 
 
 
 
118,121

 
7,732

 

 
 
 
 
 
7,732

Net capital activities by noncontrolling interests
 
 
 
 
 
 
 
 
 
 
 
 
(28,012
)
 
(28,012
)
Balance, June 30, 2015
110,865,030

 
$
2,526,945

 
(53,559
)
 
$
(1,765
)
 
$
1,933,256

 
$
(65,600
)
 
$
132,807

 
$
4,525,643

(a)    Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.


10



PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
1. 
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, Bright Canyon Energy Corporation ("BCE") 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.
 
Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Six Months Ended 
 June 30,
 
2015
 
2014
Cash paid (received) during the period for:
 
 
 
Income taxes, net of refunds
$
1,834

 
$
(131,154
)
Interest, net of amounts capitalized
84,008

 
90,707

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
38,985

 
$
19,668

Dividends accrued but not yet paid
65,933

 
62,656

 
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 revolving credit facility matures in May 2019.  At June 30, 2015, the facility was available to refinance indebtedness of the Company and for other general corporate purposes,

11

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the size of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At June 30, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
 
APS
 
On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020.  The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash used to fund capital expenditures.

On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% Notes due May 15, 2015.

On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness.
 
On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

At June 30, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million facility that matures in May 2019.  APS may increase the size 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 June 30, 2015, APS had $158 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities.
 
See "Financial Assurances" in Note 8 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):


12

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



 
As of June 30, 2015
 
As of December 31, 2014
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125

 
$
125

 
$
125

 
$
125

APS
3,544

 
3,818

 
3,290

 
3,714

Total
$
3,669

 
$
3,943

 
$
3,415

 
$
3,839

 
Debt Provisions
 
An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At June 30, 2015, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.3 billion, assuming APS’s total capitalization remains the same.


13

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



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.
  
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 the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);
 
Implementation of a Lost Fixed Cost Recovery ("LFCR") 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

14

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



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");
 
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 September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.
 

15

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 Megawatt ("MW") of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with an appropriate amount of distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.
 
On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million.

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million.
 
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 required 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 March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. Consistent with the ACC’s March 11, 2014 order, APS intends to continue its other approved DSM programs in 2015.

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.
 
Electric Energy Efficiency

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified.  The ACC held a series of three workshops in March and April 2014

16

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



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.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rule making has not been initiated and there has been no additional action on the draft to date.
 
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 2015 and 2014 (dollars in millions):
 
 
Six Months Ended 
 June 30,
 
2015
 
2014
Beginning balance
$
7

 
$
21

Deferred fuel and purchased power costs — current period
(12
)
 
(1
)
Amounts charged to customers
(11
)
 
(19
)
Ending balance
$
(16
)
 
$
1

 
The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh.  Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters In July 2008, the United States Federal Energy Regulatory Commission ("FERC") approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement, 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.

17

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



 
Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 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, 2014.

Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 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, 2015.

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future.
 
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 LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  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 files for a LFCR adjustment every January.  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. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March.

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 Arizona 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.  A series of workshops in this docket were held in 2014 and early 2015. No further action has been taken by the ACC to date.


18

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address 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. 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 fixed charge does not increase APS's revenue because it is credited to the LFCR.
 
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.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.  In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. 
 
On April 2, 2015, APS filed an application with the ACC seeking to increase the fixed grid access charge to $3.00 per kilowatt, or approximately $21 per month for a typical new residential solar customer, effective August 1. Customers who installed rooftop solar panels prior to January 1, 2014 would continue to be grandfathered and would not pay a grid access charge, and those who installed panels between January 1, 2014 and the effective date of the requested change would continue paying a charge of $0.70 per kilowatt. Solar customers that take electric service under APS’s demand-based ECT-2 residential rate, an existing rate that includes time-of-use rates with a demand charge, are not subject to the grid access charge.

APS cannot predict the outcome of this filing. The proposed grid access charge adjustment is designed to moderate the cost shift discussed above on an interim basis until the issue is further addressed in APS’s next general rate case.

On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket.
   
Four Corners
 
On December 30, 2013, APS purchased Southern California Edison Company's ("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. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This includes the deferral for future recovery of all non-fuel operating costs 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 through its inclusion in rates.  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 $74 million as of June 30, 2015 and is being amortized in rates over 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals

19

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



of the ACC decision approving the rate adjustments. APS has intervened and will actively participate in the proceeding. We cannot predict when or how this appeal will be resolved.
 
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.  Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  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 are 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.  If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

Cholla

After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Unit 2 of the Cholla Power Plant ("Cholla") by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ("EPA") approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case. On April 14, 2015, the ACC approved APS's proposed retirement of Cholla Unit 2 in accordance with the ACC's Integrated Resource Planning rules. The ACC expressly stated that this approval does not imply any specific treatment or recommendation for rate making purposes.
If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($125 million as of June 30, 2015), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.

20

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in millions):
 
 
Remaining
Amortization Period
 
June 30, 2015
 
December 31, 2014
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension benefits
(a)
 
$

 
$
505

 
$

 
$
485

Income taxes — allowance for funds used during construction ("AFUDC") equity
2044
 
5

 
122

 
5

 
118

Deferred fuel and purchased power — mark-to-market (Note 7)
2018
 
53

 
62

 
51

 
46

Transmission vegetation management
2016
 
9

 

 
9

 
5

Coal reclamation
2026
 

 
6

 

 
7

Palo Verde VIEs (Note 6)
2046
 

 
26

 

 
35

Deferred compensation
2036
 

 
36

 

 
34

Deferred fuel and purchased power (b) (c)
2015
 

 

 
7

 

Tax expense of Medicare subsidy
2024
 
2

 
13

 
2

 
14

Loss on reacquired debt
2034
 
1

 
16

 
1

 
16

Income taxes — investment tax credit basis adjustment
2044
 
2

 
46

 
2

 
46

Pension and other postretirement benefits deferral
2015
 

 

 
4

 

Four Corners cost deferral
2024
 
7

 
67

 
7

 
70

Lost fixed cost recovery (b)
2016
 
45

 

 
38

 

Retired power plant costs
2033
 
10

 
131

 
10

 
136

Deferred property taxes
(d)
 

 
40

 

 
30

Other
Various
 
1

 
11

 
2

 
12

Total regulatory assets (e)
 
 
$
135

 
$
1,081

 
$
138

 
$
1,054


(a)
This asset represents the future recovery of 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)
Per the provision of the 2012 Settlement Agreement.
(e)
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, Transmission Cost Adjustor and Other Transmission Matters."


21

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



The detail of regulatory liabilities is as follows (dollars in millions):
 
 
Remaining
Amortization Period
 
June 30, 2015
 
December 31, 2014
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Removal costs
(a)
 
$
44

 
$
245

 
$
31

 
$
273

Asset retirement obligations
2044
 

 
272

 

 
296

Renewable energy standard (b)
2017
 
29

 
20

 
25

 
23

Income taxes — change in rates
2043
 
1

 
71

 

 
72

Spent nuclear fuel
2047
 
3

 
68

 
5

 
66

Deferred gains on utility property
2019
 
2

 
7

 
2

 
8

Income taxes — deferred investment tax credit
2043
 
3

 
92

 
4

 
93

Deferred fuel and purchased power (b) (c)
2016
 
16

 

 

 

Demand side management (b)
2017
 
8

 
27

 
31

 

Other postretirement benefits
(d)
 
33

 
189

 
32

 
199

Other
Various
 
13

 
26

 
1

 
21

Total regulatory liabilities
 
 
$
152

 
$
1,017

 
$
131

 
$
1,051


(a)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Subject to a carrying charge.
(d)
See Note 4.

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 an other postretirement benefit plan 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 dates. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of these plan changes in 2014, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new account to pay for active union employee medical costs.
 
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 and $4 million for the three and six months ended June 30, 2015 and 2014, 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):


22

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
Service cost — benefits earned during the period
$
14

 
$
12

 
$
30

 
$
27

 
$
4

 
$
5

 
$
8

 
$
9

Interest cost on benefit obligation
31

 
33

 
62

 
65

 
7

 
11

 
14

 
23

Expected return on plan assets
(45
)
 
(39
)
 
(90
)
 
(79
)
 
(9
)
 
(13
)
 
(18
)
 
(25
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost

 

 

 

 
(9
)
 

 
(19
)
 

Net actuarial loss
8

 
3

 
16

 
5

 

 

 
2

 

Net periodic benefit cost
$
8

 
$
9

 
$
18

 
$
18

 
$
(7
)
 
$
3

 
$
(13
)
 
$
7

Portion of cost charged to expense
$
5

 
$
5

 
$
11

 
$
11

 
$
(2
)
 
$
3

 
$
(4
)
 
$
5

 
Contributions
 
We have made voluntary contributions of $80 million to our pension plan year-to-date in 2015. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.
 
5. 
Income Taxes
 
On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015, resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations were accounted for in the Condensed Consolidated Balance Sheets as of December 31, 2014.

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.
 
As of June 30, 2015, the tax year ended December 31, 2011 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 2009.

6.
Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lease agreements include fixed rate renewal periods. On July 7, 2014, APS notified the lessor trust entities of APS's intent to exercise the fixed rate lease renewal options. The length of the renewal options will result in APS retaining the assets

23

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $49 million in 2015, $23 million annually for the period 2016 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to 2 years, or return the assets to the lessors.

The fixed rate renewal periods give APS the ability to utilize the assets for a significant portion of the assets’ 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.
 
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for the three and six months ended June 30, 2015 of $5 million and $9 million, respectively, and for the three and six months ended June 30, 2014 of $9 million and $18 million, respectively, entirely attributable to the noncontrolling interests. The income attributable to the noncontrolling interests decreased because of lower rent income resulting from the July 7, 2014 lease extensions.

In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.
 
Our Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):
 
 
June 30, 2015
 
December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
119

 
$
121

Current maturities of long-term debt
1

 
13

Equity — Noncontrolling interests
133

 
152

 
Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders.  Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of June 30, 2015, APS would have been required to pay the noncontrolling equity participants approximately $114 million and assume $1 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.

24

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



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

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 11 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

25

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



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 June 30, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
3,808

 
GWh
Gas
 
188

 
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 and six months ended June 30, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
 
2015
 
2014
 
2015
 
2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)
 
OCI — derivative instruments
 
$
41

 
$
66

 
$
(286
)
 
$
243

Loss reclassified from accumulated OCI into income (effective portion realized) (a)
 
Fuel and purchased power (b)
 
(1,430
)
 
(3,216
)
 
(3,773
)
 
(7,654
)

(a)
During the three and six months ended June 30, 2015 and 2014, 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 $4 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, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.


26

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended June 30,
Commodity Contracts
 
 
2015
 
2014
 
2015
 
2014
Net gain (loss) recognized in income
 
Operating revenues (a)
 
$
(66
)
 
$
155

 
$
(114
)
 
$
63

Net gain (loss) recognized in income
 
Fuel and purchased power (a)
 
10,613

 
4,805

 
(34,190
)
 
22,912

Total
 
 
 
$
10,547

 
$
4,960

 
$
(34,304
)
 
$
22,975


(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 June 30, 2015 and December 31, 2014, each include gross liabilities of $4 million of derivative instruments designated as hedging instruments.
 
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2015 and December 31, 2014.  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.

27

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



As of June 30, 2015:
(Dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance  Sheet
Current assets
 
$
25,485

 
$
(12,925
)
 
$
12,560

 
$
2,162

 
$
14,722

Investments and other assets
 
20,560

 
(4,787
)
 
15,773

 
2,740

 
18,513

Total assets
 
46,045

 
(17,712
)
 
28,333

 
4,902

 
33,235

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(83,203
)
 
30,626

 
(52,577
)
 
(8,096
)
 
(60,673
)
Deferred credits and other
 
(92,475
)
 
4,786

 
(87,689
)
 

 
(87,689
)
Total liabilities
 
(175,678
)
 
35,412

 
(140,266
)
 
(8,096
)
 
(148,362
)
Total
 
$
(129,633
)
 
$
17,700

 
$
(111,933
)
 
$
(3,194
)
 
$
(115,127
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $17,700.
(c)
Represents cash collateral, cash margin and option premiums that are 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 $8,096, cash margin provided to counterparties of $2,162 and option premiums of $2,740.
 
As of December 31, 2014:
(Dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance  Sheet
Current assets
 
$
28,562

 
$
(15,127
)
 
$
13,435

 
$
350

 
$
13,785

Investments and other assets
 
24,810

 
(7,190
)
 
17,620

 

 
17,620

Total assets
 
53,372

 
(22,317
)
 
31,055

 
350

 
31,405

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(86,062
)
 
33,829

 
(52,233
)
 
(7,443
)
 
(59,676
)
Deferred credits and other
 
(82,990
)
 
32,388

 
(50,602
)
 

 
(50,602
)
Total liabilities
 
(169,052
)
 
66,217

 
(102,835
)
 
(7,443
)
 
(110,278
)
Total
 
$
(115,680
)
 
$
43,900

 
$
(71,780
)
 
$
(7,093
)
 
$
(78,873
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $43,900.
(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 $7,443, and cash margin provided to counterparties of $350.

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 one counterparty for which our exposure represents approximately 81% of Pinnacle West’s $33 million of risk management assets as of June 30, 2015.  This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties. 

28

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



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 June 30, 2015 (dollars in millions):
 
June 30, 2015
Aggregate fair value of derivative instruments in a net liability position
$
176

Cash collateral posted
18

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
89


(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 $161 million if our debt credit ratings were to fall below investment grade.

8.
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 Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified

29

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

On March 11, 2015, the DOE notified APS that it had approved APS’s claim for damages incurred due to DOE’s breach of the Standard Contract for the period July 1, 2011 through June 30, 2014. The claim for this period was the first claim made pursuant to the terms of the August 18, 2014 settlement agreement. The amount claimed was $42.0 million; APS’s share of this amount is $12.2 million. The settlement payment was received on June 1, 2015. APS’s $12.2 million share was recorded as an adjustment to a regulatory liability and had no impact on income.

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 $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of $12.98 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 liability 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 ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment 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").  APS is subject to retrospective premium 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 $23.1 million for each retrospective premium 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 $61.7 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
  
During the quarter our purchase obligations have increased by about $170 million relating to gas generation projects. The expected payments to be made are $26 million in 2015, $89 million in 2016, $46 million in 2017 and $9 million in 2018.
    

30

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Other than the item described above, there have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2014 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, 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.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
 
Southwest Power Outage
 
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.
 
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 fully briefed and pending before the United States Court of Appeals for the Ninth Circuit.  We are unable to predict the outcome of this matter.
 
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

31

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



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 sought to have the court enjoin operations at Four Corners until APS applied for and obtained any required NSR permits and complied with the NSPS.  The plaintiffs further requested the court to order the payment of civil penalties, including a beneficial mitigation project.  The case was held in abeyance while APS negotiated a settlement with the United States Department of Justice ("DOJ") and environmental plaintiffs.  In March 2015, the parties agreed in principle on final proposed language to settle the case, and on June 24, 2015, DOJ lodged the proposed consent decree with the United States District Court for the District of New Mexico. On that same day, DOJ also published notice of the filing in the Federal Register, which opened a 30-day period for public comment. The settlement would resolve claims by the government and environmental plaintiffs that the co-owners violated the Clean Air Act by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement would require installation of pollution control technology and implementation of other measures to reduce sulfur dioxide and nitrogen oxide emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule best available retrofit technology ("BART") requirements. The settlement would also require Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.2 million for certain environmental mitigation projects to benefit the Navajo Nation. APS would be responsible for 15 percent of these costs based on its ownership interest in the units at the time of the alleged violations, which does not result in a material impact on our financial position, results of operations or cash flows. APS expects DOJ to file a motion to enter the consent decree with the court after expiration of the 30-day comment period.

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, Cholla and the Navajo Generating Station ("Navajo Plant").  EPA and ADEQ will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. 

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $400 million.  In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. The cost of the controls related to the 7% interest is approximately $45 million.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million.  In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process.

32

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS




Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $200 million, 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. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rule-making processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On June 10, 2015, ADEQ issued for public comment the draft Cholla permit, which memorializes APS's proposal, and a proposed revision to the SIP, which would incorporate the new permit terms.  APS is unable to predict when or whether APS's proposal may ultimately be approved.
 
Mercury and Air Toxic Standards ("MATS").  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, which would be avoided if EPA approves APS's compromise proposal discussed above. 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, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million. The United States Supreme Court’s recent decision in Michigan vs. EPA reversed and remanded the MATS rule.  This decision does not materially impact APS.  Regardless of whether the MATS rule is ultimately vacated by the lower court, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla.
 
Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.
Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks

33

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.
APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million.

Other future environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, greenhouse gas ("GHG") emissions (such as the EPA’s proposed "Clean Power Plan" rule), 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.

 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.  On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The New Mexico Taxation and Revenue Department has indicated it intends to appeal the decision. We cannot predict the timing or outcome of any appeal; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
 

34

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Financial Assurances
 
APS has entered into various agreements that require letters of credit for financial assurance purposes.  At June 30, 2015, 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.  Two of these letters of credit expire in 2016 and one expires in 2017.  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 $20 million at June 30, 2015.  Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements, including a natural gas tolling contract entered into with a third party.  At June 30, 2015, $35 million of such letters of credit were outstanding that will expire in 2015 and 2016.
 
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
 
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2015.

9.
Other Income and Other Expense
 
The following table provides detail of other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
2015
 
2014
Other income:
 

 
 

 
 

 
 

Interest income
$
184

 
$
495

 
$
294

 
$
746

Miscellaneous
(9
)
 
2,286

 
116

 
4,402

Total other income
$
175

 
$
2,781

 
$
410

 
$
5,148

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(1,952
)
 
$
(2,620
)
 
$
(4,200
)
 
$
(4,992
)
Investment losses — net
(650
)
 
(105
)
 
(1,145
)
 
(246
)
Miscellaneous
(7
)
 
2,217

 
(1,550
)
 
46

Total other expense
$
(2,609
)
 
$
(508
)
 
$
(6,895
)
 
$
(5,192
)
 

35

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



10.
Earnings Per Share
 
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2015 and 2014 (in thousands, except per share amounts):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
2015
 
2014
Net income attributable to common shareholders
$
122,902

 
$
132,458

 
$
139,024

 
$
148,224

Weighted average common shares outstanding — basic
110,986

 
110,565

 
110,958

 
110,546

Net effect of dilutive securities: