PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/2/2018
Quarterly Report
v3.8.0.1
Document and Entity Information - shares
3 Months Ended
Mar. 31, 2018
Apr. 25, 2018
Entity Information [Line Items]    
Entity Registrant Name PINNACLE WEST CAPITAL CORP  
Entity Central Index Key 0000764622  
Document Type 10-Q  
Document Period End Date Mar. 31, 2018  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Large Accelerated Filer  
Entity Common Stock, Shares Outstanding   111,933,168
Document Fiscal Year Focus 2018  
Document Fiscal Period Focus Q1  
APS    
Entity Information [Line Items]    
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Central Index Key 0000007286  
Document Type 10-Q  
Document Period End Date Mar. 31, 2018  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Non-accelerated Filer  
Entity Common Stock, Shares Outstanding   71,264,947
Document Fiscal Year Focus 2018  
Document Fiscal Period Focus Q1  
v3.8.0.1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($)
shares in Thousands, $ in Thousands
3 Months Ended
Mar. 31, 2018
Mar. 31, 2017
OPERATING REVENUES $ 692,714 $ 677,728
OPERATING EXPENSES    
Fuel and purchased power 197,110 212,395
Operations and maintenance 265,682 226,071
Depreciation and amortization 144,825 127,627
Taxes other than income taxes 53,600 43,836
Other expenses 163 388
Total 661,380 610,317
OPERATING INCOME 31,334 67,411
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 14,079 9,482
Pension and other postretirement non-service credits - net 12,859 6,095
Other income (Note 9) 3,985 480
Other expense (Note 9) (3,229) (3,680)
Total 27,694 12,377
INTEREST EXPENSE    
Interest charges 58,954 51,864
Allowance for borrowed funds used during construction (6,755) (4,472)
Total 52,199 47,392
INCOME BEFORE INCOME TAXES 6,829 32,396
INCOME TAXES (1,265) 4,211
NET INCOME 8,094 28,185
Less: Net income attributable to noncontrolling interests (Note 6) 4,873 4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 3,221 $ 23,312
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING    
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) 112,017 111,728
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) 112,493 112,195
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING    
Net income attributable to common shareholders - basic (in dollars per share) $ 0.03 $ 0.21
Net income attributable to common shareholders - diluted (in dollars per share) $ 0.03 $ 0.21
APS    
OPERATING REVENUES $ 692,006 $ 677,589
OPERATING EXPENSES    
Fuel and purchased power 202,010 217,104
Operations and maintenance 254,601 219,008
Depreciation and amortization 144,112 127,208
Taxes other than income taxes 53,242 43,564
Taxes other than income taxes 163 436
Total 654,128 607,320
OPERATING INCOME 37,878 70,269
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 14,079 9,482
Pension and other postretirement non-service credits - net 13,197 6,042
Other income (Note 9) 3,772 342
Other expense (Note 9) (2,945) (3,128)
Total 28,103 12,738
INTEREST EXPENSE    
Interest charges 56,158 50,796
Allowance for borrowed funds used during construction (6,755) (4,472)
Total 49,403 46,324
INCOME BEFORE INCOME TAXES 16,578 36,683
INCOME TAXES 2,106 8,648
NET INCOME 14,472 28,035
Less: Net income attributable to noncontrolling interests (Note 6) 4,873 4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 9,599 $ 23,162
v3.8.0.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2018
Mar. 31, 2017
NET INCOME $ 8,094 $ 28,185
Derivative instruments:    
Net unrealized gain (loss), net of tax expense (96) (770)
Reclassification of net realized loss, net of tax expense 409 1,207
Pension and other postretirement benefits activity, net of tax expense 900 522
Total other comprehensive income 1,213 959
COMPREHENSIVE INCOME 9,307 29,144
Less: Comprehensive income attributable to noncontrolling interests 4,873 4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 4,434 24,271
APS    
NET INCOME 14,472 28,035
Derivative instruments:    
Net unrealized gain (loss), net of tax expense (96) (770)
Reclassification of net realized loss, net of tax expense 409 1,207
Pension and other postretirement benefits activity, net of tax expense 857 611
Total other comprehensive income 1,170 1,048
COMPREHENSIVE INCOME 15,642 29,083
Less: Comprehensive income attributable to noncontrolling interests 4,873 4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 10,769 $ 24,210
v3.8.0.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2018
Mar. 31, 2017
Net unrealized loss, tax expense $ 96 $ 674
Reclassification of net realized loss, tax expense (benefit) (82) 356
Pension and other postretirement benefits activity, tax benefit (expense) 443 704
Arizona Public Service Company    
Net unrealized loss, tax expense 96 674
Reclassification of net realized loss, tax expense (benefit) (82) 356
Pension and other postretirement benefits activity, tax benefit (expense) $ 306 $ 590
v3.8.0.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($)
$ in Thousands
Mar. 31, 2018
Dec. 31, 2017
CURRENT ASSETS    
Cash and cash equivalents $ 15,440 $ 13,892
Customer and other receivables 212,188 305,147
Accrued unbilled revenues 118,989 112,434
Allowance for doubtful accounts (2,046) (2,513)
Materials and supplies (at average cost) 257,815 264,012
Fossil fuel (at average cost) 48,062 25,258
Assets from risk management activities (Note 7) 1,994 1,931
Deferred fuel and purchased power regulatory asset (Note 4) 74,585 75,637
Other regulatory assets (Note 4) 178,490 172,451
Other current assets 51,887 48,039
Total current assets 957,404 1,016,288
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Note 12) 861,439 871,000
Other special use funds (Note 12) 217,992 32,542
Other assets 58,177 52,040
Total investments and other assets 1,137,608 955,582
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 17,896,772 17,798,061
Accumulated depreciation and amortization (6,231,918) (6,128,535)
Net 11,664,854 11,669,526
Construction work in progress 1,453,610 1,291,498
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 108,678 109,645
Intangible assets, net of accumulated amortization 262,523 257,189
Nuclear fuel, net of accumulated amortization 135,400 117,408
Total property, plant and equipment 13,625,065 13,445,266
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,200,260 1,202,302
Assets for other postretirement benefits (Note 5) 89,378 268,978
Other 138,591 130,666
Total deferred debits 1,428,229 1,601,946
TOTAL ASSETS 17,148,306 17,019,082
CURRENT LIABILITIES    
Accounts payable 205,169 256,442
Accrued taxes 194,930 148,946
Accrued interest 51,335 56,397
Common dividends payable 0 77,667
Short-term borrowings (Note 3) 369,900 95,400
Current maturities of long-term debt (Note 3) 582,000 82,000
Customer deposits 75,759 70,388
Liabilities from risk management activities (Note 7) 67,743 59,252
Liabilities for asset retirements 6,397 4,745
Regulatory liabilities (Note 4) 136,535 100,086
Other current liabilities 184,623 246,529
Total current liabilities 1,874,391 1,197,852
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3) 4,290,533 4,789,713
DEFERRED CREDITS AND OTHER    
Deferred income taxes 1,689,601 1,690,805
Regulatory liabilities (Note 4) 2,415,417 2,452,536
Liabilities for asset retirements 677,629 674,784
Liabilities for pension benefits (Note 5) 284,007 327,300
Liabilities from risk management activities (Note 7) 47,626 37,170
Customer advances 109,629 113,996
Coal mine reclamation 231,512 231,597
Deferred investment tax credit 205,428 205,575
Unrecognized tax benefits 13,229 13,115
Other 155,633 148,909
Total deferred credits and other 5,829,711 5,895,787
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 111,961,963 and 111,816,170 issued at respective dates 2,620,261 2,614,805
Treasury stock at cost; 29,097 and 64,463 shares at respective dates (2,431) (5,624)
Total common stock 2,617,830 2,609,181
Retained earnings 2,454,268 2,442,511
Accumulated other comprehensive loss (52,341) (45,002)
Total shareholders’ equity 5,019,757 5,006,690
Noncontrolling interests (Note 6) 133,914 129,040
Total equity 5,153,671 5,135,730
TOTAL LIABILITIES AND EQUITY 17,148,306 17,019,082
Arizona Public Service Company    
CURRENT ASSETS    
Cash and cash equivalents 14,001 13,851
Customer and other receivables 198,703 292,791
Accrued unbilled revenues 118,989 112,434
Allowance for doubtful accounts (2,046) (2,513)
Materials and supplies (at average cost) 256,573 262,630
Fossil fuel (at average cost) 48,062 25,258
Assets from risk management activities (Note 7) 1,994 1,931
Deferred fuel and purchased power regulatory asset (Note 4) 74,585 75,637
Other regulatory assets (Note 4) 178,490 172,451
Other current assets 45,477 41,055
Total current assets 934,828 995,525
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Note 12) 861,439 871,000
Other special use funds (Note 12) 215,800 30,358
Other assets 41,019 36,796
Total investments and other assets 1,118,258 938,154
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 17,751,964 17,654,078
Accumulated depreciation and amortization (6,144,874) (6,041,965)
Net 11,607,090 11,612,113
Construction work in progress 1,424,023 1,266,636
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 108,678 109,645
Intangible assets, net of accumulated amortization 262,363 257,028
Nuclear fuel, net of accumulated amortization 135,400 117,408
Total property, plant and equipment 13,537,554 13,362,830
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,200,260 1,202,302
Assets for other postretirement benefits (Note 5) 85,515 265,139
Other 132,336 129,801
Total deferred debits 1,418,111 1,597,242
TOTAL ASSETS 17,008,751 16,893,751
CURRENT LIABILITIES    
Accounts payable 198,025 247,852
Accrued taxes 211,455 157,349
Accrued interest 48,828 55,533
Common dividends payable 0 77,700
Short-term borrowings (Note 3) 255,500 0
Current maturities of long-term debt (Note 3) 582,000 82,000
Customer deposits 75,759 70,388
Liabilities from risk management activities (Note 7) 67,743 59,252
Liabilities for asset retirements 5,898 4,192
Regulatory liabilities (Note 4) 136,535 100,086
Other current liabilities 180,005 243,922
Total current liabilities 1,761,748 1,098,274
DEFERRED CREDITS AND OTHER    
Deferred income taxes 1,741,907 1,742,485
Regulatory liabilities (Note 4) 2,415,417 2,452,536
Liabilities for asset retirements 669,247 666,527
Liabilities for pension benefits (Note 5) 263,985 306,542
Liabilities from risk management activities (Note 7) 47,626 37,170
Customer advances 109,629 113,996
Coal mine reclamation 215,615 215,830
Deferred investment tax credit 205,428 205,575
Unrecognized tax benefits 43,990 43,876
Other 140,440 133,779
Total deferred credits and other 5,853,284 5,918,316
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Total common stock 178,162 178,162
Additional paid-in capital 2,571,696 2,571,696
Retained earnings 2,548,591 2,533,954
Accumulated other comprehensive loss (30,851) (26,983)
Total shareholders’ equity 5,267,598 5,256,829
Noncontrolling interests (Note 6) 133,914 129,040
Total equity 5,401,512 5,385,869
Long-term debt less current maturities (Note 3) 3,992,207 4,491,292
Total capitalization 9,393,719 9,877,161
TOTAL LIABILITIES AND EQUITY $ 17,008,751 $ 16,893,751
v3.8.0.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares
Mar. 31, 2018
Dec. 31, 2017
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]    
Common stock, par value (in dollars per share)
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 111,961,963 111,816,170
Treasury stock at cost, shares (in shares) 29,097 64,463
v3.8.0.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2018
Mar. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME $ 8,094 $ 28,185
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 163,566 147,861
Deferred fuel and purchased power (18,950) (988)
Deferred fuel and purchased power amortization 20,002 (4,172)
Allowance for equity funds used during construction (14,079) (9,482)
Deferred income taxes (229) 10,357
Deferred investment tax credit (147) (344)
Change in derivative instruments fair value 0 (101)
Stock compensation 10,537 9,997
Changes in current assets and liabilities:    
Customer and other receivables 89,518 47,007
Accrued unbilled revenues (6,555) 6,723
Materials, supplies and fossil fuel (16,607) (667)
Income tax receivable 0 (5,780)
Other current assets (664) (17,353)
Accounts payable (25,738) 22,147
Accrued taxes 45,984 43,706
Other current liabilities (12,030) (101,801)
Change in margin and collateral accounts — assets (396) (12)
Change in margin and collateral accounts — liabilities (1,092) 0
Change in other long-term assets (3,369) (36,836)
Change in other long-term liabilities (70,973) 1,604
Net cash flow provided by operating activities 166,872 140,051
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (361,037) (348,824)
Contributions in aid of construction 8,569 5,975
Allowance for borrowed funds used during construction (6,755) (4,472)
Proceeds from nuclear decommissioning trust sales 130,456 151,126
Investment in nuclear decommissioning trust (131,027) (151,696)
Other (1,299) (793)
Net cash flow used for investing activities (361,093) (348,684)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 0 255,441
Short-term borrowing and payments — net 263,500 22,097
Short-term debt borrowings under revolving credit facility 36,000 8,000
Short-term debt repayments under revolving credit facility (25,000) 0
Dividends paid on common stock (75,903) (71,177)
Common stock equity issuance - net of purchases (2,828) (11,580)
Other 0 (1)
Net cash flow provided by financing activities 195,769 202,780
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 1,548 (5,853)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 13,892 8,881
CASH AND CASH EQUIVALENTS AT END OF PERIOD 15,440 3,028
Supplemental disclosure of cash flow information    
Income taxes, net of refunds 0 (2)
Interest, net of amounts capitalized 56,026 54,280
Significant non-cash investing and financing activities:    
Accrued capital expenditures 86,991 79,306
Arizona Public Service Company    
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME 14,472 28,035
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 162,853 147,443
Deferred fuel and purchased power (18,950) (988)
Deferred fuel and purchased power amortization 20,002 (4,172)
Allowance for equity funds used during construction (14,079) (9,482)
Deferred income taxes 533 8,899
Deferred investment tax credit (147) (344)
Change in derivative instruments fair value 0 (101)
Changes in current assets and liabilities:    
Customer and other receivables 90,647 60,782
Accrued unbilled revenues (6,555) 6,723
Materials, supplies and fossil fuel (16,747) (631)
Other current assets (1,237) (15,007)
Accounts payable (24,592) 22,847
Accrued taxes 54,106 47,817
Other current liabilities (15,771) (88,990)
Change in margin and collateral accounts — assets (396) (12)
Change in margin and collateral accounts — liabilities (1,092) 0
Change in other long-term assets 4,118 (31,172)
Change in other long-term liabilities (69,836) 1,888
Net cash flow provided by operating activities 177,329 173,535
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (355,039) (343,139)
Contributions in aid of construction 8,569 5,975
Allowance for borrowed funds used during construction (6,755) (4,472)
Proceeds from nuclear decommissioning trust sales 130,456 151,126
Investment in nuclear decommissioning trust (131,027) (151,696)
Other (1,183) (774)
Net cash flow used for investing activities (354,979) (342,980)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 0 255,441
Short-term borrowing and payments — net 255,500 (19,003)
Short-term debt borrowings under revolving credit facility 25,000 0
Short-term debt repayments under revolving credit facility (25,000) 0
Dividends paid on common stock (77,700) (72,900)
Net cash flow provided by financing activities 177,800 163,538
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 150 (5,907)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 13,851 8,840
CASH AND CASH EQUIVALENTS AT END OF PERIOD 14,001 2,933
Supplemental disclosure of cash flow information    
Income taxes, net of refunds 0 0
Interest, net of amounts capitalized 54,873 53,129
Significant non-cash investing and financing activities:    
Accrued capital expenditures $ 86,944 $ 78,977
v3.8.0.1
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Arizona Public Service Company
Arizona Public Service Company
Common Stock
Arizona Public Service Company
Additional Paid-In Capital
Arizona Public Service Company
Retained Earnings
Arizona Public Service Company
Accumulated Other Comprehensive Income (Loss)
Arizona Public Service Company
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2016   111,392,053 55,317         71,264,947        
Balance at beginning of period at Dec. 31, 2016 $ 4,935,912 $ 2,596,030 $ (4,133) $ 2,255,547 $ (43,822) $ 132,290 $ 5,037,970 $ 178,162 $ 2,421,696 $ 2,331,245 $ (25,423) $ 132,290
Increase (Decrease) in Shareholders' Equity                        
Net income 28,185     23,312   4,873 28,035     23,162   4,873
Other comprehensive income 959       959   1,048       1,048  
Other (1)                 (2)   1
Issuance of common stock (in shares)   194,995                    
Issuance of common stock (988) $ (988)                    
Purchase of treasury stock (in shares) [1]     (153,470)                  
Purchase of treasury stock [1] (12,141)   $ (12,141)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     179,592                  
Reissuance of treasury stock for stock-based compensation and other 14,013   $ 14,004 8   1            
Ending balance (in shares) at Mar. 31, 2017   111,587,048 29,195         71,264,947        
Balance at end of period at Mar. 31, 2017 $ 4,965,940 $ 2,595,042 $ (2,270) 2,278,867 (42,863) 137,164 5,067,052 $ 178,162 2,421,696 2,354,405 (24,375) 137,164
Beginning balance (in shares) at Dec. 31, 2017 111,816,170 111,816,170 64,463         71,264,947        
Balance at beginning of period at Dec. 31, 2017 $ 5,135,730 $ 2,614,805 $ (5,624) 2,442,511 (45,002) 129,040 5,385,869 $ 178,162 2,571,696 2,533,954 (26,983) 129,040
Increase (Decrease) in Shareholders' Equity                        
Net income 8,094     3,221   4,873 14,472     9,599   4,873
Other comprehensive income 1,213       1,213   1,170       1,170  
Other             1     0   1
Dividends on common stock (16)     (16)                
Issuance of common stock (in shares)   145,793                    
Issuance of common stock 5,456 $ 5,456                    
Purchase of treasury stock (in shares) [1]     (81,177)                  
Purchase of treasury stock [1] (6,277)   $ (6,277)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     116,543                  
Reissuance of treasury stock for stock-based compensation and other 9,471   $ 9,470 0   1            
Reclassification of income tax effects related to new tax reform (See Note 13) $ 0     8,552 (8,552)         5,038 (5,038)  
Ending balance (in shares) at Mar. 31, 2018 111,961,963 111,961,963 29,097         71,264,947.000        
Balance at end of period at Mar. 31, 2018 $ 5,153,671 $ 2,620,261 $ (2,431) $ 2,454,268 $ (52,341) $ 133,914 $ 5,401,512 $ 178,162 $ 2,571,696 $ 2,548,591 $ (30,851) $ 133,914
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.8.0.1
Consolidation and Nature of Operations
3 Months Ended
Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Consolidation and Nature of Operations
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC ("4CA"), 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.
 
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 2017 Form 10-K.

These consolidated financial statements and notes have been prepared consistently, with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income and APS's Condensed Consolidated Statements of Income. Beginning in quarter ended March 31, 2018, APS changed the format of presentation of its Condensed Consolidated Statements of Income from a utility ratemaking format to a commercial format. Minor changes were made in the description of certain income statement line items and the amounts presented in the comparable prior period also changed by immaterial amounts due to the change from a utility to a non-utility format and also from the adoption of the new accounting guidance for net periodic pension cost and net periodic postretirement benefit cost. In addition, the prior year amounts were reclassified to conform to the current year presentation for the other special use funds in the investment and other assets section on the Condensed Consolidated Balance Sheets.

Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2018
 
2017
Cash paid (received) during the period for:
 
 
 
Income taxes, net of refunds
$

 
$
(2
)
Interest, net of amounts capitalized
56,026

 
54,280

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
86,991

 
$
79,306

v3.8.0.1
Revenue
3 Months Ended
Mar. 31, 2018
Revenue from Contract with Customer [Abstract]  
Revenue
Revenue

Adoption of Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers
On January 1, 2018, we adopted new revenue guidance in ASU 2014-09 and related amendments. The new revenue guidance requires entities to recognize revenue when control of the promised good or service is transferred to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We applied the new guidance using the modified retrospective method applied to contracts which were not completed as of January 1, 2018. The adoption of the new revenue guidance resulted in expanded disclosures, but otherwise did not have a material impact on our financial statements. New revenue disclosures required by the standard are included below. See Note 13 for additional information regarding the new accounting standard.

Revenue Recognition and Sources of Revenue

Our revenues are primarily derived from sales of electricity to our regulated retail customers. Our retail electric services and tariff rates are regulated by the ACC. Revenues related to the sale of electric services are recognized when service is rendered or electricity is delivered to the customer. Electricity sales generally represent a single performance obligation delivered over time. We have elected to apply the invoice practical expedient and, as such, we recognize revenue based on the amount to which we have a right to invoice for services performed.

The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands):
 
 
Three Months Ended March 31,
 
 
2018
Retail residential electric service
 
$
316,675

Retail non-residential electric service
 
343,189

Wholesale energy sales
 
12,089

Transmission services for others
 
14,845

Other sources
 
5,916

Total operating revenues
 
$
692,714





The billing of regulated retail electricity sales to individual customers is based on data obtained from the customer’s meter. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. We do not assess transactions for significant financing components when the period of time between when the goods or services are transferred to the customer and when the customer pays for those goods or services is less than one year.

Unbilled revenues are estimated by applying an average revenue per kilowatt-hour (“kWh”) to the number of estimated kWhs delivered but not billed by customer class. Historically, differences between the actual and estimated unbilled revenues have been immaterial. We exclude sales tax and franchise fees on electric revenues from both revenue and taxes other than income taxes.

Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers' energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC").

In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Revenue Activities

Our revenues are primarily derived from activities that are classified as revenues from contracts with customers. This includes sales of electricity to our regulated retail customers and wholesale and transmission activities. Our revenues from contracts with customers for the three months ended March 31, 2018 were $683 million.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three months ended March 31, 2018, our revenues that do not qualify as revenue from contracts with customers were $10 million. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheet as of March 31, 2018.
v3.8.0.1
Long-Term Debt and Liquidity Matters
3 Months Ended
Mar. 31, 2018
Debt Disclosure [Abstract]  
Long-Term Debt and Liquidity Matters
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.
 
Pinnacle West
 
At March 31, 2018, Pinnacle West had a $200 million facility that matures in May 2021. 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, 2018, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $37.4 million of commercial paper borrowings.

At March 31, 2018, Pinnacle West had a $125 million 364-day unsecured revolving credit facility that matures on July 30, 2018.  Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At March 31, 2018, Pinnacle West had $77 million outstanding under the facility.
 
APS

At March 31, 2018, APS had two revolving credit facilities totaling $1 billion, including a $500 million facility that matures in May 2021 and a $500 million credit facility that matures in June 2022. 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, 2018, APS had $255.5 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.
 
See "Financial Assurances" in Note 8 for a discussion of APS’s other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of March 31, 2018
 
As of December 31, 2017
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
298,326

 
$
293,061

 
$
298,421

 
$
298,608

APS
4,574,207

 
4,845,665

 
4,573,292

 
5,006,348

Total
$
4,872,533

 
$
5,138,726

 
$
4,871,713

 
$
5,304,956

 
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, 2018, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $5.3 billion, and total capitalization was approximately $10.0 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $4.0 billion, assuming APS’s total capitalization remains the same.
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Regulatory Matters
3 Months Ended
Mar. 31, 2018
Regulated Operations [Abstract]  
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%).

On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as 4.54%).

Other key provisions of the agreement include the following:

an agreement by APS not to file another general retail rate case application before June 1, 2019;
an authorized return on common equity of 10.0%;
a capital structure comprised of 44.2% debt and 55.8% common equity;
a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;
a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at the Four Corners Power Plant ("Four Corners");
a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;
an expansion of the Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party battery storage costs;
a new AZ Sun II program (now known as "APS Solar Communities") for utility-owned solar distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("RES"), to be no less than $10 million per year, and not more than $15 million per year;
an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;
rate design changes, including:
a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;
non-grandfathered distributed generation ("DG") customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;
a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and
an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.

On August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the 2017 Settlement Agreement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated.   APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated, and APS has filed a motion to intervene. Mr. Woodward filed his opening brief on March 28, 2018.  APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact on our financial position, results of operations or cash flows.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.  The complainant is requesting that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing.  In April 2018, the judge set a procedural schedule for this matter and a hearing is scheduled for September 2018. APS cannot predict the outcome of this matter.

Prior 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.  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.

Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case 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.
  
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.    

In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 megawatts ("MW") of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.  The costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement.  On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program requiring APS to spend $10 million -$15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. The ACC has not yet ruled on APS's 2018 RES Implementation Plan.
    
In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. On January 30, 2018, ACC Commissioner Tobin proposed a new standard in this proceeding which would broaden the RES to include a series of energy policies tied to clean energy sources (the "Energy Modernization Plan"). The Energy Modernization Plan includes replacing the current RES standard with the Energy Modernization Plan. APS cannot predict the outcome of this proceeding.

Demand Side Management Adjustor Charge ("DSMAC").  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. 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 ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standards; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its Lost Fixed Cost Recovery Mechanism (“LFCR”) mechanism.

On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan.

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018.   On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million.

 PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2018 and 2017 (dollars in thousands):
 
 
Three Months Ended 
 March 31,
 
2018
 
2017
Beginning balance
$
75,637

 
$
12,465

Deferred fuel and purchased power costs — current period
18,950

 
988

Amounts refunded/(charged) to customers
(20,002
)
 
4,172

Ending balance
$
74,585

 
$
17,625


 
The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017 the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh. The PSA rate for the PSA year beginning February 1, 2018 is $0.004555 per kWh, consisting of a forward component of $0.002009 per kWh and a historical component of $0.002546 per kWh.
 
Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters In July 2008, 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 Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 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, 2017.

On January 31, 2017, APS made a filing with FERC to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans.  A transmission customer intervened and protested certain aspects of APS’s filing.  FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed.  APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 2017.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) beginning in its 2018 annual transmission formula rate update filing. These modifications will reduce APS’s transmission rates compared to the rate that would have gone into effect absent these changes. This matter is still pending and APS is currently unable to predict the outcome of the proceeding.

 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 DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first 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. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh.  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 kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  DG sales losses are determined from the metered output from the DG units.
 
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). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its LFCR Adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease from 2017 levels). Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS.

Tax Expense Adjustor Mechanism ("TEAM") and FERC Tax Filing.  As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017, the Tax Act was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps.  The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit.  APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million for the remainder of 2018 through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction was effective for the first billing cycle in March 2018.

The amount of the  benefit of the lower federal income tax rate is based on our quarterly pre-tax earnings pattern, while the reduction in revenues from lower customer rates through the TEAM is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.

The second step will address the amortization of excess deferred taxes previously collected from customers. APS is analyzing the final impact of the Tax Act provisions related to deferred taxes and intends to make a second TEAM filing later in 2018.
    
The TEAM expressly applies to APS's retail rates with the exception noted above. As discussed under "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters" above, APS made a filing with FERC on March 7, 2018 seeking authorization to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 Rate Case Decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed.  The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;
Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively, to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. On March 6, 2018, Burns filed an objection to the proposed final order from the Superior Court and a motion to amend his complaint. This motion has been fully briefed and the parties are awaiting a decision from the Superior Court judge. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter.

In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

Renewable Energy Ballot Initiative
    
On February 20, 2018, a coalition of renewable energy advocates filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to procure 50% of their energy supply from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The stated goal of the Clean Energy for a Healthy Arizona coalition is to complete the necessary steps to allow the initiative to be placed on the November 2018 Arizona elections ballot. The coalition must present over 225,000 verifiable signatures to the Secretary of State by July 5, 2018 to meet that goal. APS opposes this effort. APS believes the initiative is irresponsible and would result in negative impacts to Arizona utility customers, the Arizona economy and our company. In April 2018, Arizona passed a law limiting penalties associated with violating this proposed constitutional amendment to no more than $5,000 per violation. APS cannot predict the outcome of this matter.

Energy Modernization Plan

On January 30, 2018, ACC Commissioner Tobin proposed the Energy Modernization Plan, which consists of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plans ("IRP") process. The Energy Modernization Plan includes replacing the current RES standard with the Energy Modernization Plan. The ACC has not yet initiated any formal proceedings with respect to Commissioner Tobin’s proposal; however, on February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. As a part of this proposal, the ACC voted in March 2018 to direct utilities to develop a comprehensive biomass generation plan to be included in each utility’s RES Implementation Plan.  APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop fifteen-year IRPs which describe how the utility plans to serve customer load in the plan timeframe.  IRPs are filed with the ACC every even year, and are reviewed by ACC Staff to assess the adequacy of the plans.  The ACC then determines if the IRP meets the requirements of the rule and, if so, acknowledges the IRP.  In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any plan.  APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows.  APS's next IRP will be filed in 2020.

Four Corners 

SCE-Related Matters. 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 retail 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 included 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 provided 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 $54 million as of March 31, 2018 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

 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. 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. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending, and APS cannot predict the outcome of the proceeding.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Rate Rider to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS filed the SCR Rate Rider in April 2018. Consistent with the 2017 Rate Case Decision, the rate rider filing will be narrow in scope and will address only costs associated with this specific environmental compliance equipment. Also, as provided for in the 2017 Rate Case Decision, APS will request that the rate rider become effective no later than January 1, 2019.
  
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. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.
Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($101 million as of March 31, 2018), 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. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026.
Navajo Plant
The co-owners of the Navajo Generating Station (the "Navajo Plant") and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior ("DOI") have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($95 million as of March 31, 2018) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant 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 this interest, 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.    

Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
March 31, 2018
 
December 31, 2017
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
569,784

 
$

 
$
576,188

Retired power plant costs
2033
 
26,668

 
180,298

 
27,402

 
188,843

Income taxes — allowance for funds used during construction ("AFUDC") equity
2048
 
3,818

 
143,619

 
3,828

 
142,852

Deferred fuel and purchased power — mark-to-market (Note 7)
2021
 
62,069

 
45,788

 
52,100

 
34,845

Deferred fuel and purchased power (b) (d)
2019
 
74,585

 

 
75,637

 

Four Corners cost deferral
2024
 
8,077

 
46,285

 
8,077

 
48,305

Income taxes — investment tax credit basis adjustment
2046
 
1,066

 
26,198

 
1,066

 
26,218

Lost fixed cost recovery (b)
2019
 
54,384

 

 
59,844

 

Palo Verde VIEs (Note 6)
2046
 

 
19,550

 

 
19,395

Deferred compensation
2036
 

 
37,650

 

 
36,413

Deferred property taxes
2027
 
8,569

 
73,244

 
8,569

 
74,926

Loss on reacquired debt
2038
 
1,637

 
14,896

 
1,637

 
15,305

Tax expense of Medicare subsidy
2024
 
1,235

 
7,387

 
1,236

 
7,415

Transmission cost adjustor (b)
2019
 
6,867

 

 
1,220

 

AG-1 deferral
2022
 
2,654

 
7,809

 
2,654

 
8,472

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,293

 
332

 
10,376

Coal reclamation
2026
 
1,068

 
12,468

 
1,068

 
12,396

Other
Various
 
46

 
4,991

 
3,418

 
353

Total regulatory assets (c)
 
 
$
253,075

 
$
1,200,260

 
$
248,088

 
$
1,202,302


(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 OCI and result in lower future revenues.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
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."
(d)
Subject to a carrying charge.
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
March 31, 2018
 
December 31, 2017
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - Tax Cuts and Jobs Act
(a)
 
$

 
$
1,519,224

 
$

 
$
1,520,274

Asset retirement obligations
2057
 

 
315,922

 

 
332,171

Removal costs
(b)
 
26,949

 
197,274

 
18,238

 
209,191

Other postretirement benefits
(d)
 
37,642

 
142,560

 
37,642

 
151,985

Income taxes — deferred investment tax credit
2046
 
2,144

 
52,478

 
2,164

 
52,497

Income taxes — change in rates
2046
 
2,799

 
73,703

 
2,573

 
70,537

Spent nuclear fuel
2027
 
6,609

 
61,736

 
6,924

 
62,132

Renewable energy standard (c)
2019
 
32,694

 

 
23,155

 

Demand side management (c)
2019
 
4,049

 
4,123

 
3,066

 
4,921

Sundance maintenance
2030
 

 
17,299

 

 
16,897

Deferred gains on utility property
2022
 
4,423

 
9,873

 
4,423

 
10,988

Four Corners coal reclamation
2038
 
1,858

 
18,525

 
1,858

 
18,921

Tax expense adjustor mechanism (c)
2018
 
15,676

 

 

 

Other
Various
 
1,692

 
2,700

 
43

 
2,022

Total regulatory liabilities
 
 
$
136,535

 
$
2,415,417

 
$
100,086

 
$
2,452,536


(a)
While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months. See Note 15.
(b)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(c)
See “Cost Recovery Mechanisms” discussion above.
(d)
See Note 5.
v3.8.0.1
Retirement Plans and Other Postretirement Benefits
3 Months Ended
Mar. 31, 2018
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits
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. Because of plan changes in September 2014, the Company sought IRS approval to move approximately $186 million of other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account which is included in the other special use funds on the Condensed Consolidated Balance Sheets.  The Company negotiated a draft Closing Agreement granting tentative approval from the IRS prior to the transfer. Subsequent to the transfer, the Company submitted proof of the transfer to the IRS. The Company and the IRS executed a final Closing Agreement on March 2, 2018. Per the terms of an order from FERC, the Company must also make an informational filing with FERC. The Company made this FERC filing during February 2018. It is the Company’s understanding that completion of these regulatory requirements permits access to approximately $186 million for the sole purpose of paying active union employee medical benefits.

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 or billed to electric plant participants) (dollars in thousands):

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 March 31,
 
Three Months Ended 
 March 31,
 
2018
 
2017
 
2018
 
2017
Service cost — benefits earned during the period
$
14,213

 
$
13,760

 
$
5,105

 
$
4,358

Non-service costs (credits):
 
 
 
 
 
 
 
  Interest cost on benefit obligation
31,007

 
32,701

 
7,101

 
7,565

  Expected return on plan assets
(45,667
)
 
(43,710
)
 
(10,520
)
 
(13,350
)
  Amortization of:
 

 
 
 
 

 
 

  Prior service cost (credit)

 
20

 
(9,461
)
 
(9,461
)
  Net actuarial loss
7,782

 
12,489

 

 
1,454

Net periodic benefit cost (credit)
$
7,335

 
$
15,260

 
$
(7,775
)
 
$
(9,434
)
Portion of cost (credit) charged to expense
$
2,242

 
$
7,568

 
$
(5,605
)
 
$
(4,678
)

 
On January 1, 2018, we adopted new accounting standard ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This new standard changed our income statement presentation of net periodic benefit cost/(credits) and allows only the service cost component of net periodic benefit cost to be eligible for capitalization. See Note 13 for additional information.

Contributions
 
We have made voluntary contributions of $50 million to our pension plan year-to-date in 2018. 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 $250 million during the 2018-2020 period. We do not expect to make any contributions over the next three years to our other postretirement benefit plans. Year to date in 2018, the Company was reimbursed $22 million for prior year retiree medical claims from the other postretirement benefit plan trust assets.
v3.8.0.1
Palo Verde Sale Leaseback Variable Interest Entities
3 Months Ended
Mar. 31, 2018
Variable Interest Entities [Abstract]  
Palo Verde Sale Leaseback Variable Interest Entities
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 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 expense, resulting in an increase in net income for the three months ended March 31, 2018 and 2017 of $5 million, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at March 31, 2018 and December 31, 2017 include the following amounts relating to the VIEs (dollars in thousands):
 
 
March 31, 2018
 
December 31, 2017
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
108,678

 
$
109,645

Equity — Noncontrolling interests
133,914

 
129,040


 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.
 
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 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 $295 million beginning in 2018, 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.
v3.8.0.1
Derivative Accounting
3 Months Ended
Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Accounting
Derivative Accounting
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal and emissions allowances, and in interest rates.  Risks associated with market volatility are managed 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.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may 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 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.
 
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 4).  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, 2018 and December 31, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
March 31, 2018
 
December 31, 2017
Power
 
GWh
1,277

 
583

Gas
 
Billion cubic feet
252

 
240


 
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, 2018 and 2017 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2018
 
2017
Loss Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$

 
$
(96
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(491
)
 
(851
)

(a)
During the three months ended March 31, 2018 and 2017, we had no gains or losses reclassified from accumulated OCI to earnings due to the discontinuance of cash flow hedges where the forecasted transaction is not probable of occurring.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $2 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.

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, 2018 and 2017 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2018
 
2017
Net Loss Recognized in Income
 
Operating revenues
 
$
(1,219
)
 
$
(288
)
Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(34,089
)
 
(52,627
)
Total
 
 
 
$
(35,308
)
 
$
(52,915
)

(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 following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of March 31, 2018 and December 31, 2017.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of March 31, 2018:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
5,984

 
$
(4,686
)
 
$
1,298

 
$
696

 
$
1,994

Investments and other assets
 
819

 
(819
)
 

 

 

Total assets
 
6,803

 
(5,505
)
 
1,298

 
696

 
1,994

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(69,999
)
 
4,686

 
(65,313
)
 
(2,430
)
 
(67,743
)
Deferred credits and other
 
(48,445
)
 
819

 
(47,626
)
 

 
(47,626
)
Total liabilities
 
(118,444
)
 
5,505

 
(112,939
)
 
(2,430
)
 
(115,369
)
Total
 
$
(111,641
)
 
$

 
$
(111,641
)
 
$
(1,734
)
 
$
(113,375
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin 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.  Amounts include cash collateral received from counterparties of $2,430 and cash margin provided to counterparties of $696.

As of December 31, 2017:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
5,427

 
$
(3,796
)
 
$
1,631

 
$
300

 
$
1,931

Investments and other assets
 
1,292

 
(1,241
)
 
51

 

 
51

Total assets
 
6,719

 
(5,037
)
 
1,682

 
300

 
1,982

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(59,527
)
 
3,796

 
(55,731
)
 
(3,521
)
 
(59,252
)
Deferred credits and other
 
(38,411
)
 
1,241

 
(37,170
)
 

 
(37,170
)
Total liabilities
 
(97,938
)
 
5,037

 
(92,901
)
 
(3,521
)
 
(96,422
)
Total
 
$
(91,219
)
 
$

 
$
(91,219
)
 
$
(3,221
)
 
$
(94,440
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash 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.  Amounts include cash collateral received from counterparties of $3,521 and cash margin provided to counterparties of $300.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of March 31, 2018, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties 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).