10-Q 1 pnw2016033110-q.htm 10-Q 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 March 31, 2016
 
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 April 22, 2016: 111,139,995
ARIZONA PUBLIC SERVICE COMPANY
Number of shares of common stock, $2.50 par value, outstanding as of April 22, 2016: 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 Combined Notes to 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, 2015 ("2015 Form 10-K"), Part II, Item 1A of this report 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, seasonality, 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, ballot initiatives and regulation, including those relating to environmental requirements, regulatory policy, 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 and of debt and equity capital investment;
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, including 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, including regulation of greenhouse gas emissions;
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 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 2015 Form 10-K and in Part II, Item 1A of this report, 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
 
 INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
 
 
Page
 
 
 
 
 
 



3




PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
 
 
 
OPERATING REVENUES
$
677,167

 
$
671,219

 
 
 
 
OPERATING EXPENSES
 

 
 

Fuel and purchased power
221,285

 
223,237

Operations and maintenance
243,195

 
214,944

Depreciation and amortization
119,476

 
120,949

Taxes other than income taxes
42,501

 
43,216

Other expenses
548

 
1,189

Total
627,005

 
603,535

OPERATING INCOME
50,162

 
67,684

OTHER INCOME (DEDUCTIONS)
 

 
 

Allowance for equity funds used during construction
10,516

 
9,224

Other income (Note 8)
117

 
235

Other expense (Note 8)
(4,038
)
 
(4,286
)
Total
6,595

 
5,173

INTEREST EXPENSE
 

 
 

Interest charges
50,744

 
48,399

Allowance for borrowed funds used during construction
(5,227
)
 
(4,216
)
Total
45,517

 
44,183

INCOME BEFORE INCOME TAXES
11,240

 
28,674

INCOME TAXES
1,914

 
7,947

NET INCOME
9,326

 
20,727

Less: Net income attributable to noncontrolling interests (Note 5)
4,873

 
4,605

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$
4,453

 
$
16,122

 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC
111,296

 
110,916

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED
111,847

 
111,377

 
 
 
 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 

 
 

Net income attributable to common shareholders — basic
$
0.04

 
$
0.15

Net income attributable to common shareholders — diluted
$
0.04

 
$
0.14

 
 
 
 
 
The accompanying notes are an integral part of the financial statements.


4



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(dollars in thousands)
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
 
 
 
NET INCOME
$
9,326

 
$
20,727

 
 
 
 
OTHER COMPREHENSIVE INCOME, NET OF TAX
 

 
 

Derivative instruments:
 

 
 

Net unrealized loss, net of tax expense of $546 and $473
(693
)
 
(800
)
Reclassification of realized loss, net of tax (expense) benefit of ($200) and $367
1,141

 
1,976

Pension and other postretirement benefits activity, net of tax expense of $645 and $867
530

 
583

Total other comprehensive income
978

 
1,759

 
 
 
 
COMPREHENSIVE INCOME
10,304

 
22,486

Less: Comprehensive income attributable to noncontrolling interests
4,873

 
4,605

 
 
 
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$
5,431

 
$
17,881

 
The accompanying notes are an integral part of the financial statements.


5



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 
 
March 31, 2016
 
December 31, 2015
ASSETS
 

 
 

 
 
 
 
CURRENT ASSETS
 

 
 

Cash and cash equivalents
$
14,484

 
$
39,488

Customer and other receivables
215,808

 
274,691

Accrued unbilled revenues
89,795

 
96,240

Allowance for doubtful accounts
(2,427
)
 
(3,125
)
Materials and supplies (at average cost)
234,179

 
234,234

Fossil fuel (at average cost)
44,227

 
45,697

Income tax receivable
4,637

 
589

Assets from risk management activities (Note 6)
16,089

 
15,905

Regulatory assets (Note 3)
168,753

 
149,555

Other current assets
40,480

 
37,242

Total current assets
826,025

 
890,516

INVESTMENTS AND OTHER ASSETS
 

 
 

Assets from risk management activities (Note 6)
8,612

 
12,106

Nuclear decommissioning trust (Note 11)
751,954

 
735,196

Other assets
52,679

 
52,518

Total investments and other assets
813,245

 
799,820

PROPERTY, PLANT AND EQUIPMENT
 

 
 

Plant in service and held for future use
16,285,916

 
16,222,232

Accumulated depreciation and amortization
(5,670,884
)
 
(5,594,094
)
Net
10,615,032

 
10,628,138

Construction work in progress
1,038,046

 
816,307

Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
116,418

 
117,385

Intangible assets, net of accumulated amortization
116,014

 
123,975

Nuclear fuel, net of accumulated amortization
138,424

 
123,139

Total property, plant and equipment
12,023,934

 
11,808,944

DEFERRED DEBITS
 

 
 

Regulatory assets (Note 3)
1,203,474

 
1,214,146

Assets for other postretirement benefits (Note 4)
190,458

 
185,997

Other
127,965

 
128,835

Total deferred debits
1,521,897

 
1,528,978

 
 
 
 
TOTAL ASSETS
$
15,185,101

 
$
15,028,258

 
The accompanying notes are an integral part of the financial statements.


6



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 
March 31, 2016
 
December 31, 2015
LIABILITIES AND EQUITY
 

 
 

 
 
 
 
CURRENT LIABILITIES
 

 
 

Accounts payable
$
234,946

 
$
297,480

Accrued taxes
181,889

 
138,600

Accrued interest
44,489

 
56,305

Common dividends payable

 
69,363

Short-term borrowings (Note 2)
261,800

 

Current maturities of long-term debt (Note 2)
357,580

 
357,580

Customer deposits
78,825

 
73,073

Liabilities from risk management activities (Note 6)
93,283

 
77,716

Liabilities for asset retirements
17,217

 
28,573

Deferred fuel and purchased power regulatory liability (Note 3)
13,083

 
9,688

Other regulatory liabilities (Note 3)
122,471

 
136,078

Other current liabilities
180,319

 
197,861

Total current liabilities
1,585,902

 
1,442,317

LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
3,463,032

 
3,462,391

DEFERRED CREDITS AND OTHER
 

 
 

Deferred income taxes
2,726,220

 
2,723,425

Regulatory liabilities (Note 3)
1,009,418

 
994,152

Liabilities for asset retirements
429,626

 
415,003

Liabilities for pension benefits (Note 4)
441,605

 
480,998

Liabilities from risk management activities (Note 6)
85,603

 
89,973

Customer advances
110,056

 
115,609

Coal mine reclamation
202,069

 
201,984

Deferred investment tax credit
186,966

 
187,080

Unrecognized tax benefits
9,631

 
9,524

Other
194,560

 
186,345

Total deferred credits and other
5,395,754

 
5,404,093

COMMITMENTS AND CONTINGENCIES (SEE NOTES)


 


EQUITY
 

 
 

Common stock, no par value; authorized 150,000,000 shares, 111,147,524 and 111,095,402 issued at respective dates
2,547,065

 
2,541,668

Treasury stock at cost; 7,936 and 115,030 shares at respective dates
(542
)
 
(5,806
)
Total common stock
2,546,523

 
2,535,862

Retained earnings
2,097,246

 
2,092,803

Accumulated other comprehensive loss:
 

 
 

Pension and other postretirement benefits
(37,063
)
 
(37,593
)
Derivative instruments
(6,707
)
 
(7,155
)
Total accumulated other comprehensive loss
(43,770
)
 
(44,748
)
Total shareholders’ equity
4,599,999

 
4,583,917

Noncontrolling interests (Note 5)
140,414

 
135,540

Total equity
4,740,413

 
4,719,457

 
 
 
 
TOTAL LIABILITIES AND EQUITY
$
15,185,101

 
$
15,028,258

The accompanying notes are an integral part of the financial statements.

7



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
 
Three Months Ended 
 March 31,
 
2016
 
2015
CASH FLOWS FROM OPERATING ACTIVITIES
 

 
 

Net income
$
9,326

 
$
20,727

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

 
 

Depreciation and amortization including nuclear fuel
140,759

 
141,494

Deferred fuel and purchased power
1,007

 
17,671

Deferred fuel and purchased power amortization
2,388

 
5,614

Allowance for equity funds used during construction
(10,516
)
 
(9,224
)
Deferred income taxes
3,468

 
6,978

Deferred investment tax credit
(114
)
 
(294
)
Change in derivative instruments fair value
(111
)
 
(104
)
Changes in current assets and liabilities:
 

 
 

Customer and other receivables
47,282

 
39,174

Accrued unbilled revenues
6,445

 
6,133

Materials, supplies and fossil fuel
1,525

 
(9,995
)
Income tax receivable
(4,048
)
 
(219
)
Other current assets
(8,131
)
 
(9,631
)
Accounts payable
(38,443
)
 
(35,673
)
Accrued taxes
43,289

 
48,111

Other current liabilities
(38,040
)
 
(56,747
)
Change in margin and collateral accounts — assets
681

 
(276
)
Change in margin and collateral accounts — liabilities
410

 
(13,420
)
Change in other long-term assets
(17,504
)
 
(13,126
)
Change in other long-term liabilities
4,536

 
6,955

Net cash flow provided by operating activities
144,209

 
144,148

CASH FLOWS FROM INVESTING ACTIVITIES
 

 
 

Capital expenditures
(378,500
)
 
(251,041
)
Contributions in aid of construction
12,464

 
27,222

Allowance for borrowed funds used during construction
(5,227
)
 
(4,216
)
Proceeds from nuclear decommissioning trust sales
141,809

 
115,282

Investment in nuclear decommissioning trust
(142,379
)
 
(119,594
)
Other
(472
)
 
(470
)
Net cash flow used for investing activities
(372,305
)
 
(232,817
)
CASH FLOWS FROM FINANCING ACTIVITIES
 

 
 

Issuance of long-term debt

 
250,000

Short-term borrowings and payments — net
261,800

 
(102,900
)
Dividends paid on common stock
(67,611
)
 
(64,061
)
Common stock equity issuance - net of purchases
8,902

 
9,690

Other
1

 

Net cash flow provided by financing activities
203,092

 
92,729

 
 
 
 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(25,004
)
 
4,060

 
 
 
 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
39,488

 
7,604

 
 
 
 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
14,484

 
$
11,664

The accompanying notes are an integral part of the financial statements.


8



PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(dollars in thousands)
 
Common Stock
 
Treasury Stock
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Noncontrolling Interests
 
Total
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
 
 
 
 
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
 
 

 
 
 

 
16,122

 

 
4,605

 
20,727

Other comprehensive income
 
 

 
 
 

 

 
1,759

 

 
1,759

Issuance of common stock
159,730

 
10,277

 
 
 

 

 

 

 
10,277

Purchase of treasury stock (a)
 
 

 
(93,280
)
 
(6,095
)
 

 

 

 
(6,095
)
Reissuance of treasury stock for stock-based compensation and other
 
 

 
109,896

 
7,230

 
7

 

 

 
7,237

Balance, March 31, 2015
110,809,492

 
$
2,523,247

 
(61,784
)
 
$
(2,266
)
 
$
1,942,194

 
$
(66,382
)
 
$
156,214

 
$
4,553,007

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, January 1, 2016
111,095,402

 
$
2,541,668

 
(115,030
)
 
$
(5,806
)
 
$
2,092,803

 
$
(44,748
)
 
$
135,540

 
$
4,719,457

Net income
 
 

 
 
 

 
4,453

 

 
4,873

 
9,326

Other comprehensive income
 
 

 
 
 

 

 
978

 

 
978

Issuance of common stock
52,122

 
5,397

 
 
 

 

 

 

 
5,397

Purchase of treasury stock (a)
 
 

 
(71,962
)
 
(4,880
)
 

 

 

 
(4,880
)
Reissuance of treasury stock for stock-based compensation and other
 
 

 
179,056

 
10,144

 
(10
)
 

 
1

 
10,135

Balance, March 31, 2016
111,147,524

 
$
2,547,065

 
(7,936
)
 
$
(542
)
 
$
2,097,246

 
$
(43,770
)
 
$
140,414

 
$
4,740,413

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

The accompanying notes are an integral part of the financial statements.



9




ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands)
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
 
 
 
ELECTRIC OPERATING REVENUES
$
676,632

 
$
670,668

 
 
 
 
OPERATING EXPENSES
 

 
 

Fuel and purchased power
221,285

 
223,237

Operations and maintenance
238,711

 
209,947

Depreciation and amortization
119,446

 
120,926

Income taxes
5,850

 
12,239

Taxes other than income taxes
42,410

 
42,986

Total
627,702

 
609,335

OPERATING INCOME
48,930

 
61,333

 
 
 
 
OTHER INCOME (DEDUCTIONS)
 

 
 

Income taxes
1,815

 
2,151

Allowance for equity funds used during construction
10,516

 
9,224

Other income (Note 8)
610

 
639

Other expense (Note 8)
(4,750
)
 
(5,354
)
Total
8,191

 
6,660

 
 
 
 
INTEREST EXPENSE
 

 
 

Interest on long-term debt
46,819

 
45,428

Interest on short-term borrowings
2,077

 
1,174

Debt discount, premium and expense
1,139

 
1,134

Allowance for borrowed funds used during construction
(5,040
)
 
(4,216
)
Total
44,995

 
43,520

 
 
 
 
NET INCOME
12,126

 
24,473

 
 
 
 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873

 
4,605

 
 
 
 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
$
7,253

 
$
19,868

 
The accompanying notes are an integral part of the financial statements.

10



ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(dollars in thousands)
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
 
 
 
NET INCOME
$
12,126

 
$
24,473

 
 
 
 
OTHER COMPREHENSIVE INCOME, NET OF TAX
 

 
 

Derivative instruments:
 

 
 

Net unrealized loss, net of tax expense of $546 and $473
(693
)
 
(800
)
Reclassification of realized loss, net of tax (expense) benefit of ($200) and $367
1,141

 
1,976

Pension and other postretirement benefits activity, net of tax expense of $558 and $769
611

 
681

Total other comprehensive income
1,059

 
1,857

 
 
 
 
COMPREHENSIVE INCOME
13,185

 
26,330

Less: Comprehensive income attributable to noncontrolling interests
4,873

 
4,605

 
 
 
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
$
8,312

 
$
21,725

 
The accompanying notes are an integral part of the financial statements.


11



ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 
 
March 31,
2016
 
December 31,
2015
ASSETS
 

 
 

 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 

 
 

Plant in service and held for future use
$
16,282,405

 
$
16,218,724

Accumulated depreciation and amortization
(5,667,713
)
 
(5,590,937
)
Net
10,614,692

 
10,627,787

 
 
 
 
Construction work in progress
1,025,868

 
812,845

Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
116,418

 
117,385

Intangible assets, net of accumulated amortization
115,859

 
123,820

Nuclear fuel, net of accumulated amortization
138,424

 
123,139

Total property, plant and equipment
12,011,261

 
11,804,976

 
 
 
 
INVESTMENTS AND OTHER ASSETS
 

 
 

Nuclear decommissioning trust (Note 11)
751,954

 
735,196

Assets from risk management activities (Note 6)
8,612

 
12,106

Other assets
34,927

 
34,455

Total investments and other assets
795,493

 
781,757

 
 
 
 
CURRENT ASSETS
 

 
 

Cash and cash equivalents
4,904

 
22,056

Customer and other receivables
215,351

 
274,428

Accrued unbilled revenues
89,795

 
96,240

Allowance for doubtful accounts
(2,427
)
 
(3,125
)
Materials and supplies (at average cost)
234,179

 
234,234

Fossil fuel (at average cost)
44,227

 
45,697

Assets from risk management activities (Note 6)
16,089

 
15,905

Regulatory assets (Note 3)
168,753

 
149,555

Other current assets
39,043

 
35,765

Total current assets
809,914

 
870,755

 
 
 
 
DEFERRED DEBITS
 

 
 

Regulatory assets (Note 3)
1,203,474

 
1,214,146

Assets for other postretirement benefits (Note 4)
187,069

 
182,625

Other
127,086

 
127,923

Total deferred debits
1,517,629

 
1,524,694

 
 
 
 
TOTAL ASSETS
$
15,134,297

 
$
14,982,182

 
The accompanying notes are an integral part of the financial statements.


12



ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands) 
 
March 31,
2016
 
December 31,
2015
LIABILITIES AND EQUITY
 

 
 

 
 
 
 
CAPITALIZATION
 

 
 

Common stock
$
178,162

 
$
178,162

Additional paid-in capital
2,379,696

 
2,379,696

Retained earnings
2,155,746

 
2,148,493

Accumulated other comprehensive (loss):
 

 
 

Pension and other postretirement benefits
(19,331
)
 
(19,942
)
Derivative instruments
(6,707
)
 
(7,155
)
Total shareholder equity
4,687,566

 
4,679,254

Noncontrolling interests (Note 5)
140,414

 
135,540

Total equity
4,827,980

 
4,814,794

Long-term debt less current maturities (Note 2)
3,338,032

 
3,337,391

Total capitalization
8,166,012

 
8,152,185

CURRENT LIABILITIES
 

 
 

Short-term borrowings (Note 2)
261,800

 

Current maturities of long-term debt (Note 2)
357,580

 
357,580

Accounts payable
232,484

 
291,574

Accrued taxes
183,272

 
144,488

Accrued interest
44,224

 
56,003

Common dividends payable

 
69,400

Customer deposits
78,825

 
73,073

Liabilities from risk management activities (Note 6)
93,283

 
77,716

Liabilities for asset retirements
17,217

 
28,573

Deferred fuel and purchased power regulatory liability (Note 3)
13,083

 
9,688

Other regulatory liabilities (Note 3)
122,471

 
136,078

Other current liabilities
172,249

 
180,535

Total current liabilities
1,576,488

 
1,424,708

DEFERRED CREDITS AND OTHER
 

 
 

Deferred income taxes
2,767,124

 
2,764,489

Regulatory liabilities (Note 3)
1,009,418

 
994,152

Liabilities for asset retirements
429,626

 
415,003

Liabilities for pension benefits (Note 4)
420,110

 
459,065

Liabilities from risk management activities (Note 6)
85,603

 
89,973

Customer advances
110,056

 
115,609

Coal mine reclamation
202,069

 
201,984

Deferred investment tax credit
186,966

 
187,080

Unrecognized tax benefits
35,356

 
35,251

Other
145,469

 
142,683

Total deferred credits and other
5,391,797

 
5,405,289

COMMITMENTS AND CONTINGENCIES (SEE NOTES)


 


 
 
 
 
TOTAL LIABILITIES AND EQUITY
$
15,134,297

 
$
14,982,182


The accompanying notes are an integral part of the financial statements.


13



ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
 
Three Months Ended 
 March 31,
 
2016
 
2015
CASH FLOWS FROM OPERATING ACTIVITIES
 

 
 

Net income
$
12,126

 
$
24,473

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

 
 

Depreciation and amortization including nuclear fuel
140,729

 
141,471

Deferred fuel and purchased power
1,007

 
17,671

Deferred fuel and purchased power amortization
2,388

 
5,614

Allowance for equity funds used during construction
(10,516
)
 
(9,224
)
Deferred income taxes
3,394

 
2,427

Deferred investment tax credit
(114
)
 
(294
)
Change in derivative instruments fair value
(111
)
 
(104
)
Changes in current assets and liabilities:
 

 
 

Customer and other receivables
47,575

 
43,070

Accrued unbilled revenues
6,445

 
6,133

Materials, supplies and fossil fuel
1,525

 
(9,995
)
Other current assets
(8,172
)
 
(9,116
)
Accounts payable
(34,999
)
 
(35,604
)
Accrued taxes
38,784

 
59,057

Other current liabilities
(28,748
)
 
(65,290
)
Change in margin and collateral accounts — assets
681

 
(276
)
Change in margin and collateral accounts — liabilities
410

 
(13,421
)
Change in other long-term assets
(17,375
)
 
(16,253
)
Change in other long-term liabilities
(1,102
)
 
12,635

Net cash flow provided by operating activities
153,927

 
152,974

CASH FLOWS FROM INVESTING ACTIVITIES
 

 
 

Capital expenditures
(369,861
)
 
(250,930
)
Contributions in aid of construction
12,464

 
27,222

Allowance for borrowed funds used during construction
(5,040
)
 
(4,216
)
Proceeds from nuclear decommissioning trust sales
141,809

 
115,282

Investment in nuclear decommissioning trust
(142,379
)
 
(119,594
)
Other
(472
)
 
(470
)
Net cash flow used for investing activities
(363,479
)
 
(232,706
)
CASH FLOWS FROM FINANCING ACTIVITIES
 

 
 

Issuance of long-term debt

 
250,000

Short-term borrowings and payments — net
261,800

 
(102,900
)
Dividends paid on common stock
(69,400
)
 
(65,800
)
Net cash flow provided by financing activities
192,400

 
81,300

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(17,152
)
 
1,568

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
22,056

 
4,515

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
4,904

 
$
6,083

Supplemental disclosure of cash flow information
 

 
 

Cash paid during the period for:
 

 
 

Income taxes, net of refunds
$
8,772

 
$
184

Interest, net of amounts capitalized
$
55,580

 
$
52,825

Significant non-cash investing and financing activities:
 

 
 

Accrued capital expenditures
$
59,707

 
$
56,165

 
The accompanying notes are an integral part of the financial statements.


14




ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(dollars in thousands)
 
Common Stock
 
 
 
Additional Paid-In Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Noncontrolling Interests
 
Total
 
Shares
 
Amount
 
 
 
 
 
 
 
 
 
 
Balance, January 1, 2015
71,264,947

 
$
178,162

 
$
2,379,696

 
$
1,968,718

 
$
(48,333
)
 
$
151,609

 
$
4,629,852

Net income
 
 

 

 
19,868

 

 
4,605

 
24,473

Other comprehensive income
 
 

 

 

 
1,857

 

 
1,857

Other
 
 

 

 
1

 

 

 
1

Balance, March 31, 2015
71,264,947

 
$
178,162

 
$
2,379,696

 
$
1,988,587

 
$
(46,476
)
 
$
156,214

 
$
4,656,183

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, January 1, 2016
71,264,947

 
$
178,162

 
$
2,379,696

 
$
2,148,493

 
$
(27,097
)
 
$
135,540

 
$
4,814,794

Net income
 
 

 

 
7,253

 

 
4,873

 
12,126

Other comprehensive income
 
 

 

 

 
1,059

 

 
1,059

Other
 
 

 

 

 

 
1

 
1

Balance, March 31, 2016
71,264,947

 
$
178,162

 
$
2,379,696

 
$
2,155,746

 
$
(26,038
)
 
$
140,414

 
$
4,827,980


The accompanying notes are an integral part of the financial statements.



15



COMBINED 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 5 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.
 
Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.
 
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2015 Form 10-K.
 
Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2016
 
2015
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,502

 
$
1,832

Interest, net of amounts capitalized
56,139

 
53,555

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
59,707

 
$
56,165

 
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, to refinance indebtedness, and for other general corporate purposes.
 

16


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West
 
At March 31, 2016, Pinnacle West had a $200 million revolving credit facility that matures in May 2019.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At March 31, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
 
APS

During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.

On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. 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 March 31, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and a $500 million facility that matures in May 2019.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2016, APS had $262 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.
 
See "Financial Assurances" in Note 7 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 presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of March 31, 2016
 
As of December 31, 2015
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
3,695,612

 
4,136,022

 
3,694,971

 
3,981,367

Total
$
3,820,612

 
$
4,261,022

 
$
3,819,971

 
$
4,106,367

 
Debt Provisions
 
An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At March 31, 2016, APS was in

17


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.7 billion, and total capitalization was approximately $8.6 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.4 billion, assuming APS’s total capitalization remains the same.

3.
Regulatory Matters
 
Retail Rate Case Filings with the Arizona Corporation Commission

Upcoming Rate Case Filing

On January 29, 2016, APS filed a notice of its intent to file a rate case ("NOI") informing the ACC that APS intends to submit a rate case application in June 2016 using an adjusted test year ending December 31, 2015.  The NOI provides an overview of the key issues APS expects to address in its formal request such as rate design changes (residential, commercial and industrial), permission to defer for potential future recovery costs associated with the Ocotillo Modernization Project, permission to defer for potential future recovery costs associated with environmental standards compliance, inclusion of post-test year plant and modifications to certain adjustor mechanisms, among other items.  In its rate application, APS will request that its proposed pricing changes take effect in July 2017. APS is still developing the exact amount of the request.

Prior Rate Case Filing
 
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:

18


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 
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 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");
  
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.

19


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  
In accordance with the ACC's decision on APS's 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 megawatts ("MW") of APS-owned grid scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of grid 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, called the "Solar Partner Program", is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with 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 requested 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. On January 12, 2016, the ACC approved APS’s plan and requested budget.
 
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. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from 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. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

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. On April 1, 2016, APS filed an Amended DSM Plan that sought minor modifications to its 2015 DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million.
 
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 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.


20


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 rulemaking 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 2016 and 2015 (dollars in thousands):
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
Beginning balance
$
(9,688
)
 
$
6,925

Deferred fuel and purchased power costs — current period
(1,007
)
 
(17,671
)
Amounts charged to customers
(2,388
)
 
(5,614
)
Ending balance
$
(13,083
)
 
$
(16,360
)
 
The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh.  On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017.
 
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

21


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.
 
Effective June 1, 2015, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million 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.
 
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. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. To date the ACC has not yet approved this matter.

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 electric 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 electric grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. 
 
On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing commenced in April 2016. APS cannot predict the outcome of this proceeding.


22


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015 and February 23, 2016, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS actively participated in the related hearings held in March 2016. APS has also intervened in the upcoming Tucson Electric Power Company rate case. The outcomes of these proceedings will not directly impact our financial position.

Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB")

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument was conducted on March 22, 2016.   If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter.
 
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 $69 million as of March 31, 2016 and is being amortized in rates over a total of 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 of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. We cannot predict when or how this matter 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

23


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement, which it expects to recover through its FERC-jurisdictional rates.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") 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. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and plans to seek recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its next retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($121 million as of March 31, 2016), 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.

24


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands):
 
 
Amortization Through
 
March 31, 2016
 
December 31, 2015
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
610,569

 
$

 
$
619,223

Retired power plant costs
2033
 
9,913

 
125,037

 
9,913

 
127,518

Income taxes — allowance for funds used during construction ("AFUDC") equity
2046
 
5,419

 
132,149

 
5,495

 
133,712

Deferred fuel and purchased power — mark-to-market (Note 6)
2019
 
86,160

 
69,708

 
71,852

 
69,697

Four Corners cost deferral (b)
2024
 
6,689

 
61,910

 
6,689

 
63,582

Income taxes — investment tax credit basis adjustment
2045
 
1,852

 
48,347

 
1,766

 
48,462

Lost fixed cost recovery (b)
2017
 
48,702

 

 
45,507

 

Palo Verde VIEs (Note 5)
2046
 

 
18,311

 

 
18,143

Deferred compensation
2036
 

 
35,871

 

 
34,751

Deferred property taxes
(c)
 

 
56,589

 

 
50,453

Loss on reacquired debt
2034
 
1,515

 
15,996

 
1,515

 
16,375

Tax expense of Medicare subsidy
2024
 
1,512

 
12,073

 
1,520

 
12,163

Transmission vegetation management
2016
 
2,272

 

 
4,543

 

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,957

 
332

 
11,040

Transmission cost adjustor (b)
2018
 
3,969

 
462

 

 
2,942

Coal reclamation
2026
 
418

 
5,495

 
418

 
6,085

Other
Various
 

 

 
5

 

Total regulatory assets (d)
 
 
$
168,753

 
$
1,203,474

 
$
149,555

 
$
1,214,146


(a)
This asset represents the future recovery of pension 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)
Per the provision of the 2012 Settlement Agreement.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."

    

25


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
March 31, 2016
 
December 31, 2015
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$

 
$
289,485

 
$

 
$
277,554

Removal costs
(a)
 
32,473

 
244,724

 
39,746

 
240,367

Other postretirement benefits
(d)
 
34,100

 
171,029

 
34,100

 
179,521

Income taxes — deferred investment tax credit
2045
 
3,774

 
96,940

 
3,604

 
97,175

Income taxes — change in rates
2046
 
1,771

 
71,756

 
1,113

 
72,454

Spent nuclear fuel
2047
 
31

 
71,235

 
3,051

 
67,437

Renewable energy standard (b)
2017
 
41,518

 
3,274

 
43,773

 
4,365

Demand side management (b)
2017
 
6,628

 
19,115

 
6,079

 
19,115

Sundance maintenance
2030
 

 
14,080

 

 
13,678

Deferred fuel and purchased power (b) (c)
2017
 
13,083

 

 
9,688

 

Deferred gains on utility property
2019
 
2,062

 
5,501

 
2,062

 
6,001

Four Corners coal reclamation
2031
 

 
14,725

 

 
8,920

Other
Various
 
114

 
7,554

 
2,550

 
7,565

Total regulatory liabilities
 
 
$
135,554

 
$
1,009,418

 
$
145,766

 
$
994,152


(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 Postretirement 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 the plan changes, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $140 million of the other postretirement benefit trust assets into a new trust 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 completed amortizing these costs as of June 30, 2015. We amortized approximately $2 million for the three months ended March 31, 2015.


26


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 thousands):

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 March 31,
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
2016
 
2015
Service cost — benefits earned during the period
$
14,266

 
$
15,824

 
$
3,937

 
$
4,346

Interest cost on benefit obligation
32,945

 
31,189

 
7,341

 
7,184

Expected return on plan assets
(43,792
)
 
(45,149
)
 
(9,122
)
 
(9,147
)
Amortization of:
 

 
 

 
 

 
 

Prior service cost
132

 
149

 
(9,471
)
 
(9,492
)
Net actuarial loss
9,731

 
7,761

 
946

 
1,561

Net periodic benefit cost
$
13,282

 
$
9,774

 
$
(6,369
)
 
$
(5,548
)
Portion of cost charged to expense
$
6,519

 
$
5,987

 
$
(3,126
)
 
$
(1,788
)
 
Contributions
 
We made voluntary contributions of $60 million to our pension plan year-to-date in 2016. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2016-2018 period. We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.
 
5.
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. APS will retain the assets 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 $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 period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms 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.  Predominantly due to the lease terms, 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 months ended March 31, 2016 and 2015 of $5 million, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

27


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Our Condensed Consolidated Balance Sheets at March 31, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands):
 
 
March 31, 2016
 
December 31, 2015
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
116,418

 
$
117,385

Equity — Noncontrolling interests
140,414

 
135,540

 
Assets of the VIEs are restricted and may only be used 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 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 were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $288 million beginning in 2016, and up to $456 million over the lease terms.
 
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.

6.
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.
 
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 10 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

28


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
 
Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time.  We assess hedge effectiveness both at inception and on a continuing basis.  These assessments exclude the time value of certain options.  For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings.  We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment.  As cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
 
As of March 31, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
2,239

 
GWh
Gas
 
179

 
Billion cubic feet
 
Gains and Losses from Derivative Instruments
 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2016
 
2015
Loss recognized in OCI on derivative instruments (effective portion)
 
OCI — derivative instruments
 
$
(147
)
 
$
(327
)
Loss reclassified from accumulated OCI into income (effective portion realized) (a)
 
Fuel and purchased power (b)
 
(941
)
 
(2,343
)

(a)
During the three months ended March 31, 2016 and 2015, we had no losses 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

29


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2016
 
2015
Net loss recognized in income
 
Operating revenues
 
$
(102
)
 
$
(48
)
Net loss recognized in income
 
Fuel and purchased power (a)
 
(30,936
)
 
(44,803
)
Total
 
 
 
$
(31,038
)
 
$
(44,851
)

(a)
Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed Consolidated Balance Sheets
 
Our derivative transactions are typic